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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K



(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, 2008;



OR



| ̈ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|- | ----------------------------------------------------------------------------------------



For the transition period from
 to



Commission file number: 001-32723



CNX GAS CORPORATION

(Exact name of registrant as specified in its charter)



|                                                               |  |                                     
|-------------------------------------------------------------- |  | ------------------------------------
|Delaware                                                       |  | 20-3170639                          
|(State or Other Jurisdiction of 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, including area code, of
registrants principal executive offices)



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   ̈



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   ̈    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   ̈



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.    þ



Indicate by check mark whether
the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definition of large accelerated filer, accelerated filer and small reporting
company in Rule 12b-2 of the Exchange Act.



|                           |  |                      |  |                                                  |  |                             
|-------------------------- |  | -------------------- |  | ------------------------------------------------ |  | ----------------------------
|Large accelerated filer  þ |  | Accelerated filer   ̈ |  | Non-accelerated filer   ̈                         |  | Smaller reporting company   ̈
|                           |  |                      |  | (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   ̈    No  þ



The aggregate market value of voting stock held by nonaffiliates of the
registrant as of June 30, 2008, based on the closing price of the common stock on the New York Stock Exchange on such date ($42.04 per share), was $1,163,307,506. For purposes of determining this amount, affiliates include directors and
executive officers, who, as of June 30, 2008, in the aggregate held 88,820 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 123,268,667 shares.



The number of shares outstanding of the registrants common stock as of January 29, 2009 is 150,971,636 shares.



DOCUMENTS INCORPORATED BY REFERENCE:



Portions of CNX Gas Corporations Proxy Statement for the Annual Meeting
of Stockholders to be held on April 28, 2009,

are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III









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TABLE OF CONTENTS



|           |  |                                                                                                              |  |     
|---------- |  | ------------------------------------------------------------------------------------------------------------ |  | ----
|           |  |                                                                                                              |  | Page
|           | 
|PART I     |  |                                                                                                             
|           |  |                                                                                                             
|Item 1.    |  | Business                                                                                                     |  | 4   
|           |  |                                                                                                             
|Item 1A.   |  | Risk Factors                                                                                                 |  | 22  
|           |  |                                                                                                             
|Item 1B.   |  | Unresolved Staff Comments                                                                                    |  | 33  
|           |  |                                                                                                             
|Item 2.    |  | Properties                                                                                                   |  | 33  
|           |  |                                                                                                             
|Item 3.    |  | Legal Proceedings                                                                                            |  | 33  
|           |  |                                                                                                             
|Item 4.    |  | Submission of Matters to a Vote of Security Holders                                                          |  | 33  
|           | 
|PART II    |  |                                                                                                             
|           |  |                                                                                                             
|Item 5.    |  | Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities |  | 34  
|           |  |                                                                                                             
|Item 6.    |  | Selected Financial Data                                                                                      |  | 36  
|           |  |                                                                                                             
|Item 7.    |  | Managements Discussion and Analysis of Financial Condition and Results of Operations                        |  | 40  
|           |  |                                                                                                             
|Item 7A.   |  | Quantitative and Qualitative Disclosures About Market Risk                                                   |  | 58  
|           |  |                                                                                                             
|Item 8.    |  | Financial Statements and Supplementary Data                                                                  |  | 60  
|           |  |                                                                                                             
|Item 9.    |  | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures                        |  | 102 
|           |  |                                                                                                             
|Item 9A.   |  | Controls and Procedures                                                                                      |  | 102 
|           |  |                                                                                                             
|Item 9B.   |  | Other Information                                                                                            |  | 104 
|           | 
|PART III   |  |                                                                                                             
|           |  |                                                                                                             
|Item 10.   |  | Directors and Executive Officers of the Registrant                                                           |  | 105 
|           |  |                                                                                                             
|Item 11.   |  | Executive Compensation                                                                                       |  | 106 
|           |  |                                                                                                             
|Item 12.   |  | Security Ownership of Certain Beneficial Owners and Management                                               |  | 106 
|           |  |                                                                                                             
|Item 13.   |  | Certain Relationships and Related Transactions                                                               |  | 106 
|           |  |                                                                                                             
|Item 14.   |  | Principal Accounting Fees and Services                                                                       |  | 106 
|           | 
|PART IV    |  |                                                                                                             
|           |  |                                                                                                             
|Item 15.   |  | Exhibits and Financial Statement Schedules                                                                   |  | 107 
|           | 
|SIGNATURES |  | 108                                                                                                         



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FORWARD-LOOKING STATEMENTS



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;
| | - |  | ------------------------------------------------



| |  |  | the deteriorating economic conditions in the United States and globally;
| | - |  | ------------------------------------------------------------------------



| |  |  | 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;
| | - |  | -----------------------------------------------------------------------------------------------------------



| |  |  | our ability to remove and dispose of water from the coal from which we produce gas;
| | - |  | -----------------------------------------------------------------------------------



| |  |  | the cost of removing impurities from the gas we produce may outweigh the economic benefit of selling the gas;
| | - |  | -------------------------------------------------------------------------------------------------------------



| |  |  | the availability of personnel and equipment, including our inability to retain and attract key personnel;
| | - |  | ---------------------------------------------------------------------------------------------------------



| |  |  | increased costs;
| | - |  | ----------------



| |  |  | the effects of government regulation, 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.
| | - |  | ---------------------------------------------



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PART I



|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, 2008 unless otherwise indicated. The estimates of our proved reserves as of December 31, 2008, 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 (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 millions 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 year ended December 31, 2008, 2007 and 2006 is included in Note 20 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.



General



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 we have a growing conventional and shale exploration program. CONSOL Energy Inc. (CONSOL Energy) owns 83.3% 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. CONSOL Energy
also transferred ownership or rights to natural gas, oil and certain related surface properties. As of December 31, 2008, we had 1.422 Tcfe of net proved reserves, with a PV-10 value of $2.0 billion and a standardized measure of discounted
after tax future net cash flows attributable to our proved reserves of $1.2 billion. Our proved reserves are approximately 97% CBM and 55% proved developed. We are one of the largest gas producers in the Appalachian Basin with net sales of 76.6 Bcf
for the year ended December 31, 2008. Our proved reserves are long-lived with a reserve life index of 18.6 years.



History of CNX Gas



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.



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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.



We conduct business through various subsidiaries and
affiliates including CNX Gas LLC, Cardinal States Gathering Company (GSGC), Coalfield Pipeline Company, Knox Energy Company, LLC, a 50% interest in Buchanan Generation, LLC, and various other joint ventures. These are the companies primary
responsible for the exploration, production, gathering and sale of our gas, with the exception of Buchanan Generating LLC, which uses our gas to generate electricity from a generating facility located near our Virginia gas field.



Our common stock commenced trading on the New York Stock Exchange
(NYSE) under the symbol CXG on January 19, 2006.



Our Relationship with CONSOL Energy



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.



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.



CONSOL Energy owned 83.3% of the outstanding common stock of CNX Gas as of December 31, 2008.



Coordination with Mining Activities



Approximately 24% of our 2008 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.



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Management Reorganization



On January 16, 2009, our Board of Directors implemented a reorganization of the management of CNX Gas in conjunction
with a reorganization of the management of CONSOL Energy. The changes effected by this management reorganization are as follows:



| |  |  | J. Brett Harvey, President and Chief Executive Officer of CONSOL Energy, was appointed to the additional position of Chairman and Chief Executive Officer of CNX
Gas.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Nicholas J. DeIuliius, President and Chief Executive Officer of the Company, was appointed Executive Vice President and Chief Operating Officer for CONSOL Energy.
He also will serve as President and Chief Operating Officer of the Company.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Robert F. Pusateri was appointed Executive Vice PresidentEnergy Sales and Transportation Services, for both CONSOL Energy and CNX Gas.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------



| |  |  | William J. Lyons, Executive Vice President and Chief Financial Officer of CONSOL Energy, and Chief Financial Officer of CNX Gas, is now also an Executive Vice
President of CNX Gas.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | P. Jerome Richey, Senior Vice President and General Counsel of CONSOL Energy was appointed Executive Vice PresidentCorporate Affairs and Chief Legal Officer
CONSOL Energy and CNX Gas and also will serve as Secretary to each company.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Robert P. King was appointed Executive Vice PresidentBusiness Advancement and Support Services for CONSOL Energy and CNX Gas.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------



Effective January 16, 2009, these persons are the executive officers of CNX Gas. The
purpose of this management consolidation is to improve performance and profitability of both CONSOL Energy and CNX Gas, as well as to increase efficiency and reduce costs across all business areas by creating a more unified organizational structure
that will have functional, operational, and financial responsibility for all coal, gas, and related assets, while still recognizing the separate status of CNX Gas as a public company with shareholders in addition to CONSOL Energy.



Gas Operations



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 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 have continued to increase our exploration efforts in the shale and deeper formations.



Areas of Operation



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. Our primary operating areas are:



| |  |  | Central Appalachia Virginia Operations CBM, in Southwest Virginia, 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;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Northern Appalachia Mountaineer CBM in northwestern West Virginia and southwestern Pennsylvania where we drill vertical-to-horizontal CBM wells;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Northern Appalachia Nittany CBM in central Pennsylvania, where we drill vertical CBM wells;
| | - |  | -------------------------------------------------------------------------------------------



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| |  |  | Northern Appalachia, Mountaineer-Conventional, in northwest West Virginia and southwest Pennsylvania, where we began development in 2008 in the Marcellus
Shale and shallow conventional zones, and we expect additional growth in the future;
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Tennessee, Knox-Chattanooga Shale, in eastern Tennessee, where we intend to convert our horizontal exploration program in the Chattanooga Shale into a full
scale development program;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Illinois Basin, Cardinal, in western Kentucky, Indiana and Illinois, where we are conducting an exploration program in the New Albany Shale and shallow oil
zones;
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------



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 continuation of our exploration program.



Central Appalachia



Virginia Operations CBM



We have the
right to extract CBM in this region from approximately 418,000 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 holes 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 2008, frac wells account for approximately 74% of our 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 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 collapses into the void. These upper seams become extensively fractured and release substantial volumes of gas. We drill vertical wells (called gob wells) into the gob to extract the additional
gas that is released. The extraction of gas from active gob areas generally is completed within twelve months of the start of production. Approximately 12% of our Virginia gas production comes in the form of gob gas from active coal operations.



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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. Over the past several years, we have drilled 15 of these in-mine horizontal wells, some of which have
been extended to lengths of 5,000 feet. These wells show 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 2008.



Virginia Operations Shale and Tight Sands



We have 238,000 net acres of Huron shale potential in Kentucky and Virginia; a portion of this acreage has tight sands
potential.



Tennessee



The Chattanooga Shale in Tennessee is a Devonian-age shale found at a depth
of approximately 3,500 feet. Shale thickness is between 40-80 feet, but CNX Gas has found it to be rich in total organic content. CNX Gas substantially increased its Chattanooga Shale Acreage position from 132,000 net acres to 259,000 net acres.
This was accomplished primarily by buying the remaining 50% interest in Knox Energy and several additional leasehold acquisitions. CNX Gas now has a leading acreage position in the Chattanooga Shale. Furthermore, this largely contiguous acreage is
composed of only a small number of leases, a rarity in Appalachia. CNX Gas is the operator of all of its Chattanooga Shale wells. CNX Gas believes that we drilled the first successful horizontal Chattanooga Shale well and that we have currently
drilled more horizontal wells than any other operator in this play.



Northern Appalachia



Mountaineer
CBM



We have the right to extract CBM in this region
from approximately 783,000 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
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 data points 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. The wells are spaced on approximately 480 acre sections. 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.



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Nittany CBM



We have the right to extract CBM in this region of Pennsylvania from approximately 256,000 net CBM acres. We have acquired
all of CONSOL Energys rights associated with CBM in this region as well as significant leased coal reserves from Rosebud Mining Company and a number of smaller coal owners.



Marcellus Shale



We have 186,000 net acres of Marcellus shale and 161,000 net acres of shallow conventional potential in Ohio, Pennsylvania, West Virginia, and New York.
In 2008, CNX Gas drilled and completed seven wells in the Marcellus Shale in southwestern Pennsylvania. Four wells were completed as vertical completions and three wells were drilled and completed as horizontal wells. Two wells, one vertical and one
horizontal, were turned into production as of December 31, 2008. The remaining five Marcellus wells will be turned in-line in 2009.



Shallow Oil and Gas



In 2008, CNX Gas drilled and completed two shallow conventional wells in southwestern Pennsylvania, four shallow conventional wells in south central
Pennsylvania and two shallow conventional wells in eastern Ohio. Four of these wells were completed as natural flowing wells of which two are in production. The remaining six wells are awaiting gathering pipelines and should be turned in-line early
in 2009.



Others



Cardinal Shale



As of December 31, 2008, we controlled approximately 338,000 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 2,500-4000 feet. As of
December 31, 2008, we have identified test well locations and we have drilled 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 in this area
which we will continue to evaluate.



Illinois Basin CBM



We also control 537,000 net CBM acres in Illinois and
Indiana, including 92,000 net CBM acres which contain most of the recoverable coal reserves owned or controlled by CONSOL Energy in Illinois.



Other Acreage



We have the right to extract CBM on 139,000 net acres in the San Juan Basin, 34,000 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 12,000 net acres in the San Juan Basin, 10,000 net acres in the Powder River Basin, and 40,000 net acres in various other areas.



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Summary of Properties as of December 31, 2008



|                                          |  |                   |   |  |                    |   |  |         |   |  |           |  
|----------------------------------------- |  | ----------------- | - |  | ------------------ | - |  | ------- | - |  | --------- | -
|                                          |  | CentralAppalachia |   |  | NorthernAppalachia |   |  | Other   |   |  | Total     |  
|Estimated Net Proved Reserves (Bcfe)      |  | 1,279             |   |  | 112                |   |  | 31      |   |  | 1,422     |  
|Percent Developed                         |  | 53                | % |  | 72                 | % |  | 78      | % |  | 55        | %
|Net Producing Wells (including gob wells) |  | 2,972             |   |  | 405                |   |  | 119     |   |  | 3,496     |  
|Net Proved Developed CBM Acres            |  | 143,657           |   |  | 84,013             |   |  |        |   |  | 227,670   |  
|Net Proved Undeveloped CBM Acres          |  | 31,322            |   |  | 14,621             |   |  |        |   |  | 45,943    |  
|Net Unproved CBM Acres(1)                 |  | 559,139           |   |  | 1,032,866          |   |  | 710,545 |   |  | 2,302,550 |  
|                                          |  |                   |   |  |                    |   |  |         |   |  |           |  
|Total Net CBM Acres                       |  | 734,118           |   |  | 1,131,500          |   |  | 710,545 |   |  | 2,576,163 |  
|                                          |  |                   |   |  |                    |   |  |         |   |  |           |  
|Net Proved Developed Oil & Gas Acres      |  | 6,500             |   |  | 1,807              |   |  | 213     |   |  | 8,520     |  
|Net Proved Undeveloped Oil & Gas Acres    |  | 1,864             |   |  | 902                |   |  | 60      |   |  | 2,826     |  
|Net Unproved Oil & Gas Acres(1)           |  | 492,589           |   |  | 188,407            |   |  | 398,952 |   |  | 1,079,948 |  
|                                          |  |                   |   |  |                    |   |  |         |   |  |           |  
|Total Net Oil & Gas Acres                 |  | 500,953           |   |  | 191,116            |   |  | 399,225 |   |  | 1,091,294 |  
|                                          |  |                   |   |  |                    |   |  |         |   |  |           |  



|(1) | Includes areas leased to others or participation interests in third party wells as well as small acreage in other areas.
|--- | ------------------------------------------------------------------------------------------------------------------------



Drilling



During the year ended December 31, 2008, 2007 and 2006, we drilled 534, 370, and 272 net development wells,
respectively. Gob wells and wells drilled by other operators that we participate in are excluded. As of December 31, 2008, 67 wells are still in process. The following table illustrates the wells referenced above by geographic region:



Development Wells (Net)



|                    |  |                                |  |            |  |           
|------------------- |  | ------------------------------ |  | ---------- |  | ----------
|                    |  | For the YearEnded December 31,
|                    |  | 2008 Wells                     |  | 2007 Wells |  | 2006 Wells
|Central Appalachia  |  | 321                            |  | 294        |  | 253       
|Northern Appalachia |  | 213                            |  | 76         |  | 19        
|                    |  |                                |  |            |  |           
|Total               |  | 534                            |  | 370        |  | 272       
|                    |  |                                |  |            |  |           



During the year ended
December 31, 2008, 2007 and 2006, we drilled in the aggregate 60, 9, and 4 net exploratory wells, respectively. The following table illustrates the exploratory wells by geographic region:



Exploratory Wells (Net)



|                    |  |                    |  |      |  |             |  |           |  |     |  |             |  |           |  |     |  |            
|------------------- |  | ------------------ |  | ---- |  | ----------- |  | --------- |  | --- |  | ----------- |  | --------- |  | --- |  | -----------
|                    |  | As of December 31,
|                    |  | 2008               |  | 2007 |  | 2006       
|                    |  | Producing          |  | Dry  |  | Still Eval. |  | Producing |  | Dry |  | Still Eval. |  | Producing |  | Dry |  | Still Eval.
|Central Appalachia  |  | 8                  |  |     |  | 18          |  | 3         |  |    |  |            |  | 2         |  |    |  |           
|Northern Appalachia |  | 6                  |  |     |  | 20          |  |          |  |    |  |            |  |          |  |    |  | 2          
|Other               |  | 1                  |  | 3    |  | 4           |  | 1         |  |    |  | 5           |  |          |  |    |  |           
|                    |  |                    |  |      |  |             |  |           |  |     |  |             |  |           |  |     |  |            
|Total               |  | 15                 |  | 3    |  | 42          |  | 4         |  |    |  | 5           |  | 2         |  |    |  | 2          
|                    |  |                    |  |      |  |             |  |           |  |     |  |             |  |           |  |     |  |            



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Summary of Other Operating Data



Production



The following table sets forth net sales volume produced for the periods indicated. The year ended December 31, 2008 does not include any equity
affiliates due to the proportional consolidation of Knox Energy, LLC as of December 31, 2007 and the subsequent purchase of the remaining interest in this entity. The years ended December 31, 2007 and 2006 include our portion of equity
interests.



|                      |  |                                |  |        |  |       
|--------------------- |  | ------------------------------ |  | ------ |  | ------
|                      |  | For the YearEnded December 31,
|                      |  | 2008                           |  | 2007   |  | 2006  
|Total Produced (Mmcf) |  | 76,562                         |  | 58,249 |  | 56,135



Average Sales
Prices and Lifting Costs



The following table sets forth
the average sales price and the average lifting cost (prior years include 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 YearEnded December 31,
|                                                                             |  | 2008                           |      | 2007 |   | 2006
|Average Gas Sales Price Before Effects of Financial Settlements (per Mcf)    |  | $                              | 8.99 |      | $ | 6.87 |  | $ | 6.72
|Average Effects of Financial Settlements (per Mcf)                           |  | $                              |     |      | $ | 0.33 |  | $ | 0.32
|Average Gas Sales Price Including Effects of Financial Settlements (per Mcf) |  | $                              | 8.99 |      | $ | 7.20 |  | $ | 7.04
|Average Lifting Cost (per Mcf)                                               |  | $                              | 0.89 |      | $ | 0.68 |  | $ | 0.60



Productive Wells
and Acreage



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, 2008,
the number of CNX Gas producing wells, developed acreage and undeveloped acreage:



|                                      |  |           |  |          
|------------------------------------- |  | --------- |  | ---------
|                                      |  | Gross     |  | Net(1)   
|Producing Wells (including gob wells) |  | 5,236     |  | 3,496    
|Proved Developed Acreage              |  | 246,476   |  | 236,190  
|Proved Undeveloped Acreage            |  | 50,671    |  | 48,769   
|Unproven Acreage                      |  | 3,936,252 |  | 3,382,498
|                                      |  |           |  |          
|Total Acreage                         |  | 4,233,399 |  | 3,667,457
|                                      |  |           |  |          



|(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.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Sales



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 issues, we have not failed to deliver quantities required under



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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 43.4 Bcf of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per Mcf. As of December 31, 2008, we expect these
transactions will cover approximately 41.9 Bcf of our estimated 2009 production at an average price of $9.74 per Mcf.



CNX Gas has purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2008,
CNX Gas has secured firm transportation capacity to cover more than our 2009 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 18 to the Consolidated Financial Statements.



Reserves



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,
|                                                          |  | 2008                                    |  | 2007       |  | 2006                  
|                                                          |  | ConsolidatedOperations                  |  | Affiliates |  | ConsolidatedOperations |  | Affiliates |  | ConsolidatedOperations |  | Affiliates
|Estimated proved developed reserves                       |  | 783,290                                 |  |           |  | 667,726                |  | 3,584      |  | 609,700                |  | 2,200     
|Estimated proved undeveloped reserves                     |  | 638,756                                 |  |           |  | 672,183                |  |           |  | 653,593                |  |          
|                                                          |  |                                         |  |            |  |                        |  |            |  |                        |  |           
|Total estimated proved developed and undeveloped reserves |  | 1,422,046                               |  |           |  | 1,339,909              |  | 3,584      |  | 1,263,293              |  | 2,200     
|                                                          |  |                                         |  |            |  |                        |  |            |  |                        |  |           



Discounted Future
Net Cash Flows



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(Dollars in
millions)
|                                                                         |  | As of December 31,                                   
|                                                                         |  | 2008                                                  |       | 2007 |   | 2006 
|Future net cash flows                                                    |  | $                                                     | 2,824 |      | $ | 3,609 |  | $ | 2,484
|Total PV-10 measure of pre-tax discounted future net cash flows(1)       |  | $                                                     | 2,004 |      | $ | 2,288 |  | $ | 1,500
|Total standardized measure of after tax discounted future net cash flows |  | $                                                     | 1,218 |      | $ | 1,390 |  | $ | 935  



|(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.
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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Reconciliation of PV-10 to Standardized Measure



|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|------------------------------------------------- |  | --------------------- | ------ | - | ---- | - | ------ | ---- |  | - | ------ | -
|                                                  |  | As ofDecember 31,     |       
|                                                  |  | 2008                  |        |   | 2007 |   |        | 2006 | 
|                                                  |  | (Dollars in millions) |       
|Future cash inflows                               |  | $                     | 8,857  |   |      | $ | 9,509  |      |  | $ | 7,105  |  
|Future Production Costs                           |  |                       | (3,526 | ) |      |   | (3,005 | )    |  |   | (2,569 | )
|Future Development Costs (including abandonments) |  |                       | (794   | ) |      |   | (636   | )    |  |   | (552   | )
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|Future net cash flows (pre-tax)                   |  |                       | 4,537  |   |      |   | 5,868  |      |  |   | 3,984  |  
|10% discount factor                               |  |                       | (2,533 | ) |      |   | (3,580 | )    |  |   | (2,484 | )
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|PV-10 (Non-GAAP measure)                          |  |                       | 2,004  |   |      |   | 2,288  |      |  |   | 1,500  |  
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|Undiscounted Income Taxes                         |  |                       | (1,714 | ) |      |   | (2,259 | )    |  |   | (1,500 | )
|10% discount factor                               |  |                       | 928    |   |      |   | 1,361  |      |  |   | 935    |  
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|Discounted Income Taxes                           |  |                       | (786   | ) |      |   | (898   | )    |  |   | (565   | )
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  
|Standardized GAAP measure                         |  | $                     | 1,218  |   |      | $ | 1,390  |      |  | $ | 935    |  
|                                                  |  |                       |        |   |      |   |        |      |  |   |        |  



Competition



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 gas commodity trading fundamentals and pipeline transportation availability to the diverse market opportunities.



Employee and Labor Relations



As of December 31, 2008, CNX Gas had 373 employees. None of our employees are represented by a union.



Available Information



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, the charter for the audit committee 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



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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 our website or in a report on Form 8-K filed with the Securities and Exchange Commission.



Regulations



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 and surface water 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.



Environmental Regulation of Gas Operations



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 the 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, including, but not limited to, produced water, drilling
fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic
fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted. 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 year ended 2008, 2007 and 2006 . Any environmental
costs are in addition to well plugging costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits and bonds, to gather and submit required data to regulatory
authorities, to characterize and dispose of wastes and effluents, and to maintain management and 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



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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 treatment or
disposal.



CNX Gas is subject to various generally-applicable
federal environmental laws, including but not limited to the following:



| |  |  | the Clean Air Act;
| | - |  | ------------------



| |  |  | the Clean Water Act;
| | - |  | --------------------



| |  |  | the Toxic Substances Control Act;
| | - |  | ---------------------------------



| |  |  | the Endangered Species Act;
| | - |  | ---------------------------



| |  |  | the Safe Drinking Water Act;
| | - |  | ----------------------------



| |  |  | the Comprehensive Environmental Response, Compensation and Liability Act;
| | - |  | -------------------------------------------------------------------------



| |  |  | the Resource Conservation and Recovery Act;
| | - |  | -------------------------------------------



| |  |  | the Oil Pollution 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 or civil penalties 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.



Numerous proposals have been made at
the international, national, regional and state levels that are intended to limit or capture emissions of greenhouse gases, such as methane and carbon dioxide. Several states have adopted measures intended to reduce greenhouse gas loading in the
atmosphere. If comprehensive legislation focusing on greenhouse gas emissions is enacted by the United States or individual states, it may affect the use of fossil fuels, including natural gas, as an energy source.



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.



Federal Regulation of the Sale and Transportation of Gas



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



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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 Gas 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.



State Regulation of Gas Operations



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 and spacing 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 production. A number of states have either
enacted new laws or may be considering the adequacy of existing laws affecting gathering rates



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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 we 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.



Ownership of Mineral Rights



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 their coal properties prior to conducting their coal mining operations. Given CONSOL Energys long history as a coal producer we believe they have
a well-developed ownership position relating to their coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to their coal holdings, their 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.



Pennsylvania



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.



Virginia



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. The situation may be different if there is any expression in



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the severance deed indicating more than mere coal is conveyed. Virginia courts have 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.



West
Virginia



The West Virginias 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, 2008, 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 Wells 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 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 pooling provisions under the
West Virginia Act.



Other States



We have been transferred rights to extract CBM held by CONSOL Energy in
other states where they have 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.



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GLOSSARY OF NATURAL GAS AND COAL TERMS



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.



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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.



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.



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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.



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. 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.



Executive Officers Of The Company



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).



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|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



The current financial crisis and deteriorating economic conditions may have material adverse impacts on our business and financial condition that we currently cannot predict.



As widely reported, economic conditions in the United States and globally
have been deteriorating. Financial markets in the United States, Europe and Asia have been experiencing a period of unprecedented turmoil and upheaval characterized by extreme volatility and declines in security prices, severely diminished liquidity
and credit availability, inability to access capital markets, the bankruptcy, failure, collapse or sale of various financial institutions and an unprecedented level of intervention from the United States federal government and other governments.
Unemployment has risen while business and consumer confidence have declined and there are fears of a prolonged recession. Although we cannot predict the impacts on us of the deteriorating economic conditions, they could materially adversely affect
our business and financial condition. For example:



| |  |  | the demand for natural gas may decline due to the deteriorating economic conditions which could negatively impact the revenues, margins and profitability of our
natural gas business;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | the tightening of credit or lack of credit availability to our customers could adversely affect our ability to collect our trade receivables;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our ability to access the capital markets may be restricted at a time when we would like, or need, to raise capital for our business including for exploration
and/or development of our reserves;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | our commodity hedging arrangements could become ineffective if our counterparties are unable to perform their obligations or seek bankruptcy protection.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------



Natural gas prices are volatile, and a
decline in natural gas prices would significantly affect our financial results and impede our growth.



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;
| | - |  | ----------------------------------------------------



| |  |  | domestic and foreign governmental regulations;
| | - |  | ----------------------------------------------



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| |  |  | 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.



We face uncertainties in estimating proved recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve
quantities and a lower present value of our reserves.



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.
| | - |  | ------------------------------------



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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, 2008 would decrease from $2.0 billion to $1.9 billion. The standardized GAAP measure associated with this decline of $0.10 per Mcf, would be approximately $1.2 billion.



Unless we replace our natural gas reserves, our reserves and production
will decline, which would adversely affect our business, financial condition, results of operations and cash flows.



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, 2008, 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.



Our exploration and development activities may not be commercially successful.



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.



We have a limited operating history in certain of our operating areas, and our increased focus on new development projects in these and other unexplored areas increases the risks inherent in our gas and oil
activities.



In 2009 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, Kentucky and Tennessee. These exploration, drilling and production activities will be subject to many risks, including the
risk that CBM or other natural gas is not present in sufficient quantities in the coal seam or target strata, or that sufficient permeability does not exist for



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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 for CBM, other 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.



Our business depends on transportation facilities owned by others.
Disruption of, capacity constraints in, or proximity to pipeline systems could limit sales of our gas.



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, and our unit costs will also increase. 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.



Increased industry activity may create shortages of field services, equipment and personnel, which may increase our costs and may limit our ability to drill and produce from our natural gas properties.



The demand for well service providers, related equipment, and 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. 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.



We operate in a highly competitive environment and many of our competitors have greater resources than we do.



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, our 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.



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Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential
liabilities and may be disruptive and difficult to integrate into our business.



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.



Our drilling and production operations require the removal of water from the coal, shale and other strata from which we produce gas. In addition, we
must find adequate sources of water to facilitate the drilling and fracturing process. If we are unable to acquire supplies of water for drilling or are unable to dispose of the water we use or remove from the strata at a reasonable cost and within
applicable environmental rules, our ability to produce gas commercially and in commercial quantities could be impaired.



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. Also, the cost of water disposal may affect our profitability.



We use a substantial amount of water in our gas well drilling operations. Our
inability to locate sufficient amounts of water, or dispose of water after drilling, could impact our operations. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain
operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental
regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which
cannot be predicted, all of which could have an adverse affect on our operations and financial performance.



Coalbed methane and other gas that we produce often contain impurities that must be removed, and the gas must be processed before it can be sold,
which can adversely affect our operations and financial performance.



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 produced from a particular well,
or group of wells, may outweigh the economic benefit of selling that gas. Our profitability may decrease due to the reduced production and sale of gas.



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We may be unable to retain our existing senior management team and/or our key personnel who have
expertise in coalbed methane and other natural gas extraction and our failure to continue to attract qualified new personnel could adversely affect our business.



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 and other natural gas extraction, our business could be materially adversely affected. No employment agreements have been or are expected to be executed with 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.



Government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that
govern our and CONSOL Energys businesses increase our costs and may restrict our operations.



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.



We must obtain governmental permits and approvals for drilling
operations, which can be a costly and time consuming process and result in restrictions on our operations.



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 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.



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Enactment of a Pennsylvania severance tax on natural gas could adversely impact our results of
existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.



As a result of a funding gap in the Pennsylvania state budget due to significant declines in anticipated tax revenues, the Pennsylvania
governor has proposed to its legislature the adoption of a wellhead or severance tax on the production of natural gas in Pennsylvania. The amount of the proposed tax is 5 percent of the value of the natural gas at wellhead plus 4.7 cents per 1,000
cubic feet of natural gas severed. In Pennsylvania we have rights in significant acreage for coalbed methane and other natural gas extraction on which we have drilled and expect to continue to drill producing wells. In 2008, 12%, or 9.1 bcf, of our
production was from PA. In addition, a significant amount of our Marcellus shale play acreage is in Pennsylvania. We cannot predict whether Pennsylvania will adopt any such tax, nor if adopted the rate of tax. If Pennsylvania adopts such a tax, it
could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in Pennsylvania.



We may incur additional costs and delays to produce gas because we have to acquire additional property rights to
perfect our title to the gas estate.



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
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 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 gas from coal seams and from shale 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 million of aggregate unknown liabilities; CONSOL Energy will be responsible for the next $40 million of aggregate unknown liabilities; and we will be responsible for any additional unknown liabilities over $50 million.
We will also be responsible for any unknown liabilities which were not asserted in writing by August 7, 2010.



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We must coordinate some of our gas production activities with coal mining activities in the same
area, which could adversely affect our operations and financial results.



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 their 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.



Currently the majority of our producing properties are located in three counties in southwestern Virginia, making us vulnerable to risks associated
with having our production concentrated in one area.



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.



Proposed legislation that seeks to
regulate greenhouse gas emissions could increase our costs and reduce the value of our assets.



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. Pursuant to an amendment to the master cooperation and safety agreement, CONSOL Energy and CNX Gas each
receive 50% ownership of any greenhouse gas reduction benefits of our production activities both prior to and subsequent to the 2005 separation.



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
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.



Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.



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, 2008, we had hedges on approximately 41.9 bcf of our targeted 2009 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;
| | - |  | -------------------------------------



| |  |  | the counterparties to our contracts fail to perform the contracts; or
| | - |  | ---------------------------------------------------------------------



| |  |  | the creditworthiness of our counterparties or their guarantors is substantially impaired.
| | - |  | -----------------------------------------------------------------------------------------



If our gas hedges would no longer qualify for hedge accounting, we will be
required to mark them to market and recognize the adjustments through current year earnings. This may result in more volatility in our income in future periods.



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Our future level of indebtedness and the terms of our financing arrangements may adversely affect
operations and limit our growth.



At December 31,
2008, we had $72.7 million of borrowings under our revolving credit facility. We may incur additional indebtedness in the future.



Our level of indebtedness 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
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 their board of directors and/or are employees of CONSOL Energy, creating potential conflicts of interest.



Our principal stockholder, CONSOL Energy, owns 83.3% 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.
| | - |  | ----------------------------------------------------------



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Any exercise by CONSOL Energy of their 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.



Potential conflicts may arise between us and CONSOL Energy that 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 their substantial influence and control over us in favor
of their 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 their directors, officers and employees from owing us fiduciary duties with respect to such opportunities.



Our intercompany agreements with CONSOL Energy are not the result of arms-length negotiations.



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 may be more favorable to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and their 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 agreements with CONSOL Energy may limit our ability to obtain capital, make acquisitions or effect other business combinations.



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.



A significant portion of our production is associated with the coal mining operations of CONSOL Energy and any disruption to those coal mining operations will adversely impact our production and results of
operations.



In 2008, approximately 24% of our gas
production was produced in connection with coal extraction by CONSOL Energy; 12% of our production was associated with CONSOL Energys active mining operations.



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CONSOL Energys coal mining operations can be impacted by many events, some of which are beyond
CONSOL Energys control, including for example,



| |  |  | an extended decline in prices they receive for coal;
| | - |  | ----------------------------------------------------



| |  |  | changes in the supply of and demand for coal;
| | - |  | ---------------------------------------------



| |  |  | the disruption of rail, barge and other systems that transport coal;
| | - |  | --------------------------------------------------------------------



| |  |  | the availability of qualified personnel to work in coal operations;
| | - |  | -------------------------------------------------------------------



| |  |  | work stoppages at union-represented mines;
| | - |  | ------------------------------------------



| |  |  | legal proceedings brought by property owners, environmental groups, governmental authorities and others;
| | - |  | --------------------------------------------------------------------------------------------------------



| |  |  | the risks inherent in coal mining, such as unforeseeable geological conditions, equipment failure, methane gas issues, fires, accidents and weather conditions; and
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | compliance with laws and government regulations, including the need to obtain government permits for mining operations, environmental laws and regulations and
employee health and safety regulations.
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



If
CONSOL Energys mining operations are idled or curtailed as a result of any of these factors at any coal mine where we have gas operations associated with mining operations, especially CONSOL Energys Buchanan Mine in southwest Virginia,
our CBM production would be adversely affected and the impact could have a material adverse effect on our results of operations. For example, in 2005, 2007 and 2008, CONSOL Energy was forced to idle their Buchanan Mine due to various issues. As a
result, we estimate that our total gas production was 4.0 Bcf, 3.7 Bcf and 1.3 Bcf less than it otherwise would have been in those years if the Buchanan Mine had operated at normal levels.



Further, CONSOL Energys coal mining activities at their 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.



Our prior and continuing relationship with CONSOL Energy
exposes us to risks attributable to CONSOL Energys businesses.



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 million 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.



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CONSOL Energys ownership permits them to acquire the minority interest in a transaction where
the minority stockholders have no vote and they may be faced with either accepting the consideration offered by CONSOL Energy or pursuing appraisal rights.



CONSOL Energy announced in late January 2008 a proposal to acquire all of the minority interest in CNX Gas. Although CONSOL
Energy withdrew that proposal, they could in the future determine to again pursue that proposal or a similar or a different transaction to acquire the minority interest. A merger or similar transaction involving CNX Gas normally requires a
stockholders meeting and vote of the stockholders of CNX Gas. However, under Delaware law and CNX Gas Certificate of Incorporation, stockholder action may be taken if a consent is signed by CONSOL Energy as the majority stockholder of CNX Gas.
In addition, were CONSOL Energy to acquire 90% or more of our common stock, CONSOL Energy could by itself effect a short form merger without any stockholder action or approval. Thus, the minority stockholders may not have any vote on a
merger or other transaction involving us that results in our becoming a wholly owned subsidiary of CONSOL Energy and the minority stockholders may be faced with either accepting the consideration offered by CONSOL Energy or pursuing appraisal
rights.



|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 first through seventh paragraphs of Note 19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.



EXECUTIVE OFFICERS OF REGISTRANT



Incorporated by reference into this Part I is the information set forth in Part III, Item 10 of this Form 10-K under the caption Executive
Officers of CNX Gas Corporation.



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PART II



|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.



The quarterly high and low share price for CNX Gas stock was as follows for the 2008 and 2007 quarters ended:



|             |  |      |       |      |   |       |  |     |       |  |   |      
|------------ |  | ---- | ----- | ---- | - | ----- |  | --- | ----- |  | - | -----
|             |  | 2008 |       | 2007
|             |  | High |       | Low  |   | High  |  | Low
|March 31     |  | $    | 39.53 |      | $ | 26.66 |  | $   | 28.69 |  | $ | 22.90
|June 30      |  | $    | 45.51 |      | $ | 31.82 |  | $   | 32.69 |  | $ | 27.14
|September 30 |  | $    | 42.07 |      | $ | 19.77 |  | $   | 32.24 |  | $ | 23.47
|December 31  |  | $    | 31.75 |      | $ | 14.08 |  | $   | 33.20 |  | $ | 28.50



As of
December 31, 2008 there were 10 holders of record of the Companys common stock; we believe that there are significantly more beneficial holders of our stock.



Stock Performance Graph



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 semi-annual 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, 2008.



|                                       |  |                     |        |        |        |                   |        |        |        |        |        |        |        |       
|-------------------------------------- |  | ------------------- | ------ | ------ | ------ | ----------------- | ------ | ------ | ------ | ------ | ------ | ------ | ------ | ------
|                                       |  | BasePeriodJan-19-06 |        |        |        | Six Months Ending |        |        |        |        |        |       
|Company / Index                        |  |                     | Jun-06 |        | Dec-06 |                   | Jun-07 |        | Dec-07 |        | Jun-08 |        | Dec-08
|CNX Gas Corporation                    |  | 100                 |        | 133.33 |        | 113.33            |        | 136.00 |        | 142.00 |        | 186.84 |        | 121.33
|S&P MidCap 400 Index                   |  | 100                 |        | 99.66  |        | 105.47            |        | 118.10 |        | 113.88 |        | 109.44 |        | 72.62 
|S&P Oil & Gas Exploration & Production |  | 100                 |        | 96.25  |        | 95.84             |        | 115.69 |        | 138.41 |        | 186.24 |        | 90.57 



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LOGO



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.



Recent Sales of Unregistered Securities



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 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



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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.



|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 years ended December 31, 2008, 2007, 2006 2005 and 2004 are derived from our audited consolidated financial statements, including the consolidated balance sheets at
December 31, 2008, 2007, 2006, 2005 and 2004 and the related consolidated statements of income and cash flows for each of the years ended December 31, 2008, 2007, 2006, 2005 and 2004, 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.



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CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF INCOME



STATEMENTS OF INCOME DATA



|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|----------------------------------------------------- |  | ------------------------------- | ----------- | ---- | - | -------------- |  | ---- | ----------- | ---- | - | ----------- |  | - | -----------
|                                                      |  | For the Year Ended December 31,
|                                                      |  | 2008                            |             | 2007 |   | 2006           |  | 2005 |             | 2004
|                                                      |  |                                 |             |      |   | (In thousands) |  |      |             |     
|RESULTS OF OPERATIONS                                 |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Outside Sales                                         |  | $                               | 678,793     |      | $ | 404,835        |  | $    | 385,056     |      | $ | 277,031     |  | $ | 214,721    
|Related Party Sales                                   |  |                                 | 9,532       |      |   | 11,618         |  |      | 8,490       |      |   | 6,052       |  |   | 22,036     
|Royalty Interest Gas Sales                            |  |                                 | 79,302      |      |   | 46,586         |  |      | 51,054      |      |   | 45,351      |  |   | 41,858     
|Purchased Gas Sales                                   |  |                                 | 8,464       |      |   | 7,628          |  |      | 43,973      |      |   | 275,148     |  |   | 112,005    
|Other Income                                          |  |                                 | 13,330      |      |   | 8,815          |  |      | 26,264      |      |   | 9,710       |  |   | 4,493      
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|TOTAL REVENUE AND OTHER INCOME                        |  |                                 | 789,421     |      |   | 479,482        |  |      | 514,837     |      |   | 613,292     |  |   | 395,113    
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Lifting Costs                                         |  |                                 | 67,653      |      |   | 38,721         |  |      | 33,357      |      |   | 30,399      |  |   | 27,250     
|Gathering and Compression Costs                       |  |                                 | 83,752      |      |   | 61,798         |  |      | 58,102      |      |   | 43,903      |  |   | 40,422     
|Royalty Interest Gas Costs                            |  |                                 | 74,041      |      |   | 40,011         |  |      | 41,998      |      |   | 36,641      |  |   | 32,914     
|Purchased Gas Costs                                   |  |                                 | 8,175       |      |   | 7,162          |  |      | 44,843      |      |   | 278,720     |  |   | 113,063    
|Other                                                 |  |                                 | 4,995       |      |   | 1,759          |  |      | 2,060       |      |   | 2,729       |  |   | 586        
|General and Administrative                            |  |                                 | 80,246      |      |   | 54,825         |  |      | 39,168      |      |   | 19,129      |  |   | 15,303     
|Depreciation, Depletion and Amortization              |  |                                 | 70,010      |      |   | 48,961         |  |      | 37,999      |      |   | 35,039      |  |   | 32,889     
|Interest Expense                                      |  |                                 | 7,820       |      |   | 5,606          |  |      | 870         |      |   | 14          |  |   |           
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|TOTAL COSTS AND EXPENSES                              |  |                                 | 396,692     |      |   | 258,843        |  |      | 258,397     |      |   | 446,574     |  |   | 262,427    
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Earnings Before Income Taxes                          |  |                                 | 392,729     |      |   | 220,639        |  |      | 256,440     |      |   | 166,718     |  |   | 132,686    
|Income Taxes                                          |  |                                 | 153,656     |      |   | 84,961         |  |      | 96,573      |      |   | 64,550      |  |   | 51,898     
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|NET INCOME                                            |  | $                               | 239,073     |      | $ | 135,678        |  | $    | 159,867     |      | $ | 102,168     |  | $ | 80,788     
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Earnings Per Share from Net Income:                   |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Basic                                                 |  | $                               | 1.58        |      | $ | 0.90           |  | $    | 1.06        |      | $ | 0.76        |  | $ | 0.66       
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Diluted                                               |  | $                               | 1.58        |      | $ | 0.90           |  | $    | 1.06        |      | $ | 0.76        |  | $ | 0.66       
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Weighted Average Number of Common Shares Outstanding: |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Basic                                                 |  |                                 | 150,947,516 |      |   | 150,886,433    |  |      | 150,845,518 |      |   | 134,071,334 |  |   | 122,896,667
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            
|Dilutive                                              |  |                                 | 151,331,953 |      |   | 151,133,520    |  |      | 151,017,456 |      |   | 134,137,219 |  |   | 122,988,359
|                                                      |  |                                 |             |      |   |                |  |      |             |      |   |             |  |   |            



BALANCE SHEETS DATA

(In thousands)



|                                             |  |                    |           |   |      |   |           |  |      |           |      |   |         |  |   |         |  
|-------------------------------------------- |  | ------------------ | --------- | - | ---- | - | --------- |  | ---- | --------- | ---- | - | ------- |  | - | ------- | -
|                                             |  | As of December 31, |          
|                                             |  | 2008               |           |   | 2007 |   | 2006      |  | 2005 |           | 2004 |  
|Working Capital (Deficiency) (Unaudited)     |  | $                  | (31,192   | ) |      | $ | 25,303    |  | $    | 115,824   |      | $ | 3,720   |  | $ | (35,030 | )
|Total Assets                                 |  |                    | 2,124,973 |   |      |   | 1,380,703 |  |      | 1,155,001 |      |   | 859,167 |  |   | 718,859 |  
|Long Term Debt (Including current portion)   |  |                    | 83,144    |   |      |   | 72,768    |  |      | 66,470    |      |   |        |  |   |        |  
|Total Deferred Credits and Other Liabilities |  |                    | 384,367   |   |      |   | 227,833   |  |      | 153,977   |      |   | 109,226 |  |   | 205,614 |  
|Stockholders Equity                         |  |                    | 1,384,874 |   |      |   | 1,023,237 |  |      | 880,215   |      |   | 679,472 |  |   | 462,556 |  



37



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CASH FLOW STATEMENTS DATA

(In thousands)



|                                                    |  |                                |          |   |      |   |          |      |  |   |          |   |  |      |          |   |  |   |         |  
|--------------------------------------------------- |  | ------------------------------ | -------- | - | ---- | - | -------- | ---- |  | - | -------- | - |  | ---- | -------- | - |  | - | ------- | -
|                                                    |  | For theYear Ended December 31, |         
|                                                    |  | 2008                           |          |   | 2007 |   |          | 2006 |  |   | 2005     |   |  | 2004 |         
|Net Cash Provided by Operating Activities           |  | $                              | 447,375  |   |      | $ | 272,448  |      |  | $ | 243,569  |   |  | $    | 144,997  |   |  | $ | 175,350 |  
|Net Cash Used in Investing Activities               |  |                                | (559,132 | ) |      |   | (354,227 | )    |  |   | (156,020 | ) |  |      | (108,287 | ) |  |   | (93,114 | )
|Net Cash Provided by (Used in) Financing Activities |  |                                | 81,635   |   |      |   | 6,654    |      |  |   | (449     | ) |  |      | (16,640  | ) |  |   | (82,237 | )



OTHER OPERATING DATA

(Unaudited)



|                                                                                 |  |                                |       |      |   |       |  |      |       |      |   |       |  |   |      
|-------------------------------------------------------------------------------- |  | ------------------------------ | ----- | ---- | - | ----- |  | ---- | ----- | ---- | - | ----- |  | - | -----
|                                                                                 |  | For theYear Ended December 31,
|                                                                                 |  | 2008                           |       | 2007 |   | 2006  |  | 2005 |       | 2004
|Net Sales Volumes (Bcf)(1)                                                       |  |                                | 76.56 |      |   | 58.25 |  |      | 56.14 |      |   | 48.39 |  |   | 48.56
|Average Sales Price Including Effects of Financial Settlements ($ per Mcf)(1)(2) |  | $                              | 8.99  |      | $ | 7.20  |  | $    | 7.04  |      | $ | 5.90  |  | $ | 4.90 
|Total Average Costs ($ Per Mcf)(1)                                               |  | $                              | 3.94  |      | $ | 3.55  |  | $    | 3.02  |      | $ | 2.72  |  | $ | 2.45 
|Net Estimated Proved Reserves (Bcfe)(1)(3)                                       |  |                                | 1,422 |      |   | 1,343 |  |      | 1,265 |      |   | 1,130 |  |   | 1,045



OTHER FINANCIAL DATA

(In thousands)



|                        |  |                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|----------------------- |  | ------------------------------ | ------- | ---- | - | ------- |  | ---- | ------- | ---- | - | ------- |  | - | -------
|                        |  | For theYear Ended December 31,
|                        |  | 2008                           |         | 2007 |   | 2006    |  | 2005 |         | 2004
|Capital Expenditures(4) |  | $                              | 560,663 |      | $ | 357,199 |  | $    | 154,243 |      | $ | 110,752 |  | $ | 89,753 
|EBIT(5) (Unaudited)     |  |                                | 400,149 |      |   | 222,452 |  |      | 253,857 |      |   | 166,314 |  |   | 132,686
|EBITDA(5) (Unaudited)   |  |                                | 470,159 |      |   | 271,413 |  |      | 291,856 |      |   | 201,353 |  |   | 165,575



|(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. There were no equity affiliates in the year ended December 31, 2008. Knox Energy is included in the equity earnings data in 2007, 2006, 2005 and 2004. Sales of gas produced by equity affiliates were 0.32 Bcf for the year ended
December 31, 2007, 0.22 Bcf for the year ended December 2006, 0.23 Bcf for the year ended December 31, 2005 and 0.20 Bcf for the year ended December 31, 2004.
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(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 our portion of Equity affiliates included were 3.6
Bcfe at December 31, 2007, 2.2 at December 31, 2006, 2.7 at December 31, 2005 and 2.4 at December 31, 2004. There were no equity in affiliates at December 31, 2008.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(4) | Capital expenditures for 2008 include the acquisition of the remaining interest in Knox Energy which CNX Gas did not already own, and other acquisition transactions. Capital
expenditures in 2007 include those related to Knox Energy and acquisition of mineral interests.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(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
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| | 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 YearEnded December 31,
|(In thousands)                                                                            |  | 2008                           |         | 2007 |   | 2006    |  | 2005 |         | 2004
|Net Income                                                                                |  | $                              | 239,073 |      | $ | 135,678 |  | $    | 159,867 |      | $ | 102,168 |  | $ | 80,788 
|Add: Interest Expense                                                                     |  |                                | 7,820   |      |   | 5,606   |  |      | 870     |      |   | 14      |  |   |       
|Less: Interest Income                                                                     |  |                                | 400     |      |   | 3,793   |  |      | 3,453   |      |   | 418     |  |   |       
|Add: Income Tax Expense                                                                   |  |                                | 153,656 |      |   | 84,961  |  |      | 96,573  |      |   | 64,550  |  |   | 51,898 
|                                                                                          |  |                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Earnings Before Net Interest and Taxes (EBIT)                                             |  |                                | 400,149 |      |   | 222,452 |  |      | 253,857 |      |   | 166,314 |  |   | 132,686
|Add: Depreciation, Depletion and Amortization                                             |  |                                | 70,010  |      |   | 48,961  |  |      | 37,999  |      |   | 35,039  |  |   | 32,889 
|                                                                                          |  |                                |         |      |   |         |  |      |         |      |   |         |  |   |        
|Earnings Before Net Interest, Taxes and Depreciation, Depletion and Amortization (EBITDA) |  | $                              | 470,159 |      | $ | 271,413 |  | $    | 291,856 |      | $ | 201,353 |  | $ | 165,575
|                                                                                          |  |                                |         |      |   |         |  |      |         |      |   |         |  |   |        



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##### 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.



During 2008, we achieved the following:



| |  |  | completed another year with no employee-related lost time accidents. We have accumulated over 3.5 million man hours without a lost time accident;
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | drilled a record 327 vertical frac wells in our Virginia Operations;
| | - |  | --------------------------------------------------------------------



| |  |  | drilled a record 129 wells in our Mountaineer Operations;
| | - |  | ---------------------------------------------------------



| |  |  | drilled a record 106 wells in our Nittany Operations;
| | - |  | -----------------------------------------------------



| |  |  | achieved a 100% success rate in the Marcellus Shale play. The Companys first vertical well came online in July with a peak production rate of 1.3 MMcf per
day. The Companys first horizontal well came online in October and achieved a peak production rate in December of 6.5 MMcf per day. This was, at that time, the largest reported daily production by any producer for any well in this multi-state
play;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | achieved exploration success in the Chattanooga Shale;
| | - |  | ------------------------------------------------------



| |  |  | increased our 2008 production by over 30% to 76.6 Bcf;
| | - |  | ------------------------------------------------------



| |  |  | we replaced approximately 240% of our production through the drill bit;
| | - |  | -----------------------------------------------------------------------



| |  |  | generated net income of $239 million;
| | - |  | -------------------------------------



| |  |  | maintained our low cost structure relative to our peer group; and
| | - |  | -----------------------------------------------------------------



| |  |  | invested $561 million in order to continue growing.
| | - |  | ---------------------------------------------------



CNX Gas has entered into precedent agreements with several interstate gas pipeline companies for the acquisition of approximately 114,000 dekatherms per
day of firm transportation capacity at negotiated rates, to transport current and future forecasted production within the Appalachian Basin to market once agreed upon expansions are completed by the gas pipeline companies. We expect to enter into
firm transportation contracts upon completion of the related expansion projects.



CNX Gas has completed the independent verification process for several Chicago Climate Exchange (CCX) approved projects relating to the capture of coal mine methane. In 2008, we verified and registered for trading on
the CCX approximately 8.4 million metric tons of emission offsets. 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. Sales of these emission offsets will be reflected in income as they occur. To
date, no offsets have been sold.



Our Board of Directors made
several management changes which had the effect of consolidating the management of CNX Gas and its controlling stockholder, CONSOL Energy.



Effective January 16, 2009, the goal of the management consolidation is to improve performance and profitability of both companies as well as to
increase efficiency and reduce costs across all business areas, by



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##### Table of Contents

creating a more unified organizational structure that will have functional, operational, and financial responsibility for all coal, gas, and related assets,
while still recognizing the separate status of CNX Gas as a public company with shareholders in addition to CONSOL Energy. The changes were as follows;



J. Brett Harvey, President and Chief Executive OfficerCONSOL Energy Inc. has been appointed to the additional position of Chairman and Chief
Executive Officer CNX Gas Corporation.



Nicholas J. DeIuliis
has been appointed Executive Vice President and Chief Operating Officer for CONSOL Energy. He also will serve as President and Chief Operating Officer of CNX Gas Company. DeIuliis will have overall responsibility for energy production (coal and
gas), focusing particularly on production efficiency and production coordination between coal and gas.



Robert F. Pusateri has been appointed Executive Vice PresidentEnergy Sales and Transportation
Services for both companies. He will continue to serve as President of CONSOL Energy Sales Company. Pusateri will have overall responsibility for sales of coal and gas, as well as transportation services and the management of CO2credits generated by the two companies.



William J. Lyons was named Executive Vice President and remains Chief Financial Officer. He will have responsibility for the essential financial functions
of the CONSOL Energy and CNX Gas.



P. Jerome Richey has been
appointed Executive Vice PresidentCorporate Affairs and Chief Legal Officer for both companies and also will serve as Secretary to each company.



Robert P. King has been appointed Executive Vice PresidentBusiness Advancement and Support Services for both companies. He will be responsible for
identifying and developing new business opportunities as well as managing critical, non-financial support services for both companies.



CONSOL Energy continues to beneficially own approximately 83.3% of our outstanding common stock as such, CNX Gas financial statements are
consolidated into CONSOL Energys financial statements.



41



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##### Table of Contents

Year Ended December 31, 2008 compared with Year Ended December 30, 2007

(Amounts reported in millions)



Net Income



Net income changed primarily due to the following items:



|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|---------------------------------------- |  | ---- | --- | ---- | - | -------------- |  | - | ---------------- | - |  | ----- | --
|                                         |  | 2008 |     | 2007 |   | DollarVariance |  |   | PercentageChange |  
|Revenue and Other Income:                |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Outside Sales                            |  | $    | 679 |      | $ | 405            |  | $ | 274              |   |  | 67.7  | % 
|Related Party Sales                      |  |      | 10  |      |   | 11             |  |   | (1               | ) |  | (9.1  | )%
|Royalty Interest Gas Sales               |  |      | 79  |      |   | 46             |  |   | 33               |   |  | 71.7  | % 
|Purchased Gas Sales                      |  |      | 8   |      |   | 8              |  |   |                 |   |  |      |   
|Other Income                             |  |      | 13  |      |   | 9              |  |   | 4                |   |  | 44.4  | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Revenue and Other Income           |  |      | 789 |      |   | 479            |  |   | 310              |   |  | 64.7  | % 
|Costs and Expenses:                      |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Lifting Costs                            |  |      | 68  |      |   | 38             |  |   | 30               |   |  | 78.9  | % 
|Gathering and Compression Costs          |  |      | 84  |      |   | 62             |  |   | 22               |   |  | 35.5  | % 
|Gas Royalty Interest Costs               |  |      | 74  |      |   | 40             |  |   | 34               |   |  | 85.0  | % 
|Purchased Gas Costs                      |  |      | 8   |      |   | 7              |  |   | 1                |   |  | 14.3  | % 
|Other                                    |  |      | 4   |      |   | 1              |  |   | 3                |   |  | 300.0 | % 
|General and Administrative               |  |      | 80  |      |   | 55             |  |   | 25               |   |  | 45.5  | % 
|Depreciation, Depletion and Amortization |  |      | 70  |      |   | 49             |  |   | 21               |   |  | 42.9  | % 
|Interest Expense                         |  |      | 8   |      |   | 6              |  |   | 2                |   |  | 33.3  | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Costs and Expenses                 |  |      | 396 |      |   | 258            |  |   | 138              |   |  | 53.5  | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Earnings Before Income Taxes             |  |      | 393 |      |   | 221            |  |   | 172              |   |  | 77.8  | % 
|Income Taxes                             |  |      | 154 |      |   | 85             |  |   | 69               |   |  | 81.2  | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Net Income                               |  | $    | 239 |      | $ | 136            |  | $ | 103              |   |  | 75.7  | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   



Net income for the
year ended December 31, 2008 was higher than the year ended December 31, 2007 primarily due to higher production volumes and average sales prices, offset, in part, by increased costs as discussed below.



Revenue and Other Income



Revenue and other income increased due to the following items:



|                               |  |      |     |      |   |                |  |   |                  |   |  |      |   
|------------------------------ |  | ---- | --- | ---- | - | -------------- |  | - | ---------------- | - |  | ---- | --
|                               |  | 2008 |     | 2007 |   | DollarVariance |  |   | PercentageChange |  
|Revenue and Other Income:      |  |      |     |      |   |                |  |   |                  |   |  |      |   
|Outside Sales                  |  | $    | 679 |      | $ | 405            |  | $ | 274              |   |  | 67.7 | % 
|Related Party Sales            |  |      | 10  |      |   | 11             |  |   | (1               | ) |  | (9.1 | )%
|Royalty Interest Gas Sales     |  |      | 79  |      |   | 46             |  |   | 33               |   |  | 71.7 | % 
|Purchased Gas Sales            |  |      | 8   |      |   | 8              |  |   |                 |   |  |     |   
|Other Income                   |  |      | 13  |      |   | 9              |  |   | 4                |   |  | 44.4 | % 
|                               |  |      |     |      |   |                |  |   |                  |   |  |      |   
|Total Revenue and Other Income |  | $    | 789 |      | $ | 479            |  | $ | 310              |   |  | 64.7 | % 
|                               |  |      |     |      |   |                |  |   |                  |   |  |      |   



Outside sales and
related party sales, combined, increased due primarily to higher average sales prices received and higher volumes of gas sold.



|                                                   |  |      |      |      |   |          |  |                  |      |  |      |  
|-------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- | ---- |  | ---- | -
|                                                   |  | 2008 |      | 2007 |   | Variance |  | PercentageChange |     
|Produced Gas Sales Volumes (in billion cubic feet) |  |      | 76.6 |      |   | 57.9     |  |                  | 18.7 |  | 32.3 | %
|Average Sales Price Per thousand cubic feet        |  | $    | 8.99 |      | $ | 7.19     |  | $                | 1.80 |  | 25.0 | %



42



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##### Table of Contents

The increase in average sales price is the result of CNX Gas realizing general market price increases in
the year-to-year comparison. 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 43.4 Bcf of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per Mcf. In the prior year, these financial hedges represented approximately 18.4 Bcf at an average price of
$8.01 per Mcf. Sales volumes increased as a result of additional wells coming online from our on-going drilling program. Prior year sales volumes were impacted by the deferral of production related to the Buchanan Mine issue at CONSOL Energy which
also impacted production by 1.2 Bcf during the first quarter of 2008.



|                                                           |  |      |      |      |   |          |  |                  |      |  |      |  
|---------------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- | ---- |  | ---- | -
|                                                           |  | 2008 |      | 2007 |   | Variance |  | PercentageChange |     
|Gas Royalty Interest Sales Volumes (in billion cubic feet) |  |      | 8.5  |      |   | 7.2      |  |                  | 1.3  |  | 18.1 | %
|Average Sales Price Per thousand cubic feet                |  | $    | 9.32 |      | $ | 6.44     |  | $                | 2.88 |  | 44.7 | %



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 increase in market prices, contractual differences among leases and the mix of average and index
prices used in calculating royalties contributed to the year-to-year change.



|                                                |  |      |      |      |   |          |  |   |                  |   |  |      |   
|----------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ---- | --
|                                                |  | 2008 |      | 2007 |   | Variance |  |   | PercentageChange |  
|Purchased Sales Volumes (in billion cubic feet) |  |      | 1.0  |      |   | 1.1      |  |   | (0.1             | ) |  | (9.1 | )%
|Average Sales Price Per thousand cubic feet     |  | $    | 8.76 |      | $ | 7.19     |  | $ | 1.57             |   |  | 21.8 | % 



Purchased gas sales
volumes represent volumes of gas we sold at market prices that were purchased from third-party producers, less our gathering fees.



Other income consists of the following items:



|                                 |  |      |    |      |   |                |  |   |                  |   |  |        |   
|-------------------------------- |  | ---- | -- | ---- | - | -------------- |  | - | ---------------- | - |  | ------ | --
|                                 |  | 2008 |    | 2007 |   | DollarVariance |  |   | PercentageChange |  
|Insurance settlements            |  | $    | 8  |      | $ | 2              |  | $ | 6                |   |  | 300.0  | % 
|Timber income                    |  |      | 1  |      |   |               |  |   | 1                |   |  | 100.0  | % 
|Legal settlements                |  |      | 1  |      |   |               |  |   | 1                |   |  | 100.0  | % 
|Third party gathering revenue    |  |      | 2  |      |   | 1              |  |   | 1                |   |  | 100.0  | % 
|Interest income                  |  |      |   |      |   | 4              |  |   | (4               | ) |  | (100.0 | )%
|Equity in earnings of affiliates |  |      | 1  |      |   | 2              |  |   | (1               | ) |  | (50.0  | )%
|                                 |  |      |    |      |   |                |  |   |                  |   |  |        |   
|Total Other Income               |  | $    | 13 |      | $ | 9              |  | $ | 4                |   |  | 44.4   | % 
|                                 |  |      |    |      |   |                |  |   |                  |   |  |        |   



In 2008, CNX Gas
received $8 million of proceeds from its insurance carrier as final settlement of the insurance claim related to the July 2007 Buchanan Mine event which idled the mine. The $8 million represents business interruption coverage. In 2007, CNX Gas
received a $2 million advance on the settlement of claims of proceeds from its insurance carrier.



Timber income increased $1 million in 2008 due primarily to a sale which occurred in February 2008. No assurance can be given that another sale will occur
in the future.



A litigation settlement in 2008 with a royalty
holder resulted in approximately $1 million of income.



Third-party gathering revenue increased $1 million in the year-to-year comparison due to higher third party volumes being transported on CNX Gas gathering lines.



43



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##### Table of Contents

Interest income decreased $4 million as a result of the lower average cash balance throughout 2008
compared to 2007. Lower cash balances are the result of the June 2007 acquisition of Peabodys oil and gas interests, the acquisition of the remaining 50% of Knox Energy LLC, additional capital expenditures related to the expanded drilling
program, as well as acquisition costs for additional gas acreage.



Equity in earnings of affiliates decreased $1 million due to the June 2008 acquisition of the remaining 50% interest in Knox Energy LLC.



Costs and Expenses



Costs and expenses increased due to the following items:



|                                         |  |      |     |      |   |                |  |                  |     |  |       |  
|---------------------------------------- |  | ---- | --- | ---- | - | -------------- |  | ---------------- | --- |  | ----- | -
|                                         |  | 2008 |     | 2007 |   | DollarVariance |  | PercentageChange |    
|Costs and Expenses:                      |  |      |     |      |   |                |  |                  |     |  |       |  
|Lifting Costs                            |  | $    | 68  |      |   | 38             |  |                  | 30  |  | 78.9  | %
|Gathering and Compression                |  |      | 84  |      |   | 62             |  |                  | 22  |  | 35.5  | %
|Royalty Interest Gas Costs               |  |      | 74  |      |   | 40             |  |                  | 34  |  | 85.0  | %
|Purchased Gas                            |  |      | 8   |      |   | 7              |  |                  | 1   |  | 14.3  | %
|Other                                    |  |      | 4   |      |   | 1              |  |                  | 3   |  | 300.0 | %
|General and Administrative               |  |      | 80  |      |   | 55             |  |                  | 25  |  | 45.5  | %
|Depreciation, Depletion and Amortization |  |      | 70  |      |   | 49             |  |                  | 21  |  | 42.9  | %
|Interest Expense                         |  |      | 8   |      |   | 6              |  |                  | 2   |  | 33.3  | %
|                                         |  |      |     |      |   |                |  |                  |     |  |       |  
|Total Cost and Expense                   |  | $    | 396 |      | $ | 258            |  | $                | 138 |  | 53.5  | %
|                                         |  |      |     |      |   |                |  |                  |     |  |       |  



Lifting costs
increased due to higher unit costs and higher volumes sold.



|                                                   |  |      |      |      |   |          |  |                  |  |      |  
|-------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- |  | ---- | -
|                                                   |  | 2008 |      | 2007 |   | Variance |  | PercentageChange | 
|Produced Gas Sales Volumes (in billion cubic feet) |  |      | 76.6 |      |   | 57.9     |  | 18.7             |  | 32.3 | %
|Average Lifting Costs Per thousand cubic feet      |  | $    | 0.89 |      | $ | 0.67     |  | 0.22             |  | 32.8 | %



Average lifting costs
per unit sold increased in the current year as a result of the following items:



| |  |  | Well closing costs were impaired $0.05 per thousand cubic feet in the year-to-year comparison. Well closing liabilities were adjusted in 2007 to reflect longer well
lives than were previously estimated. This adjustment resulted in a reduction to expense. The adjustments to well closing liabilities were insignificant in 2008.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Water disposal costs have increased $0.05 per thousand cubic feet due to additional volumes of water produced by CNX Gas wells in 2008.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Severance taxes per unit sold were $0.04 per thousand cubic feet sold higher in 2008. The increase in severance tax was attributable to the higher average sale
prices for gas.
| | - |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Repairs and maintenance costs have increased $0.04 per thousand cubic feet due to higher material costs and higher contract labor costs.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Fuel and chemical costs have increased $0.02 per thousand cubic feet due to higher costs of these commodities in the year-to-year comparison.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Various other costs have also increased by $0.02 per thousand cubic feet for various items which occurred throughout both years, none of which were individually
material.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                                                   |  |      |      |      |   |          |  |                  |  |      |  
|-------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- |  | ---- | -
|                                                   |  | 2008 |      | 2007 |   | Variance |  | PercentageChange | 
|Produced Gas Sales Volumes (in billion cubic feet) |  |      | 76.6 |      |   | 57.9     |  | 18.7             |  | 32.3 | %
|Average Gathering Costs Per thousand cubic feet    |  | $    | 1.09 |      | $ | 1.07     |  | 0.02             |  | 1.9  | %



44



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##### Table of Contents

The increase in average gathering and transportation unit costs was attributable to the following items.



| |  |  | Fuel and power increased $.06 per thousand cubic feet due to additional compressors being placed in service in anticipation of higher production volumes in the
future.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Compression expenses increased $0.02 per thousand cubic feet due to the additional compressors discussed above.
| | - |  | ---------------------------------------------------------------------------------------------------------------



These increases in average gathering and transportation costs were offset, in
part, by the following items:



| |  |  | Repair and maintenance expense decreased $0.05 per thousand cubic feet. Dollars spent for maintenance have remained fairly consistent in the year-to-year
comparison; therefore, additional volumes gathered and transported have lowered the related unit costs for these components.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Various other costs have decreased $0.01 per thousand cubic feet due to various transactions that occurred throughout both years, none of which were individually
material.
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------



|                                                           |  |      |      |      |   |          |  |        |      |  |      |  
|---------------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ------ | ---- |  | ---- | -
|                                                           |  | 2008 |      | 2007 |   | Variance |  | Change |     
|Gas Royalty Interest Sales Volumes (in billion cubic feet) |  |      | 8.5  |      |   | 7.2      |  |        | 1.3  |  | 18.1 | %
|Average Costs Per thousand cubic feet                      |  | $    | 8.70 |      | $ | 5.53     |  | $      | 3.17 |  | 57.3 | %



Included in royalty
interest gas costs are the expenses related to the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The increase in volumes and price relates to the volatility and contractual differences among leases, the
mix of average and index prices used in calculating royalties, and the actualization of advanced royalty payments.



|                                                |  |      |      |      |   |          |  |   |                  |   |  |      |   
|----------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ---- | --
|                                                |  | 2008 |      | 2007 |   | Variance |  |   | PercentageChange |  
|Purchased Sales Volumes (in billion cubic feet) |  |      | 1.0  |      |   | 1.1      |  |   | (0.1             | ) |  | (9.1 | )%
|Average Costs Per thousand cubic feet           |  | $    | 8.13 |      | $ | 6.66     |  | $ | 1.47             |   |  | 22.1 | % 



Purchased gas sales
volumes represent volumes of gas purchased from third-party producers, less our gathering fees, that we sell at market prices. Purchased gas volumes also include the impact of pipeline imbalances. The higher average cost per thousand cubic feet is
due to overall price increases and contractual differences among customers in the year-to-year comparison.



Other costs and expenses increased $3 million primarily due additional exploration costs incurred in 2008 compared to 2007. Additional exploration costs
are the results of the on-going ramp up of our exploration program. These costs have also increased due to the reversal of previously capitalized drilling costs related to unsuccessful wells. Capitalized costs for four wells were expensed in 2008.
There were no unsuccessful wells in 2007. Under the successful efforts method of accounting, drilling costs are capitalized until it is determined that gas can not be economically produced from the well.



General and Administrative expenses increased due to the following items:



|                                     |  |      |    |      |   |                |  |                  |    |  |       |  
|------------------------------------ |  | ---- | -- | ---- | - | -------------- |  | ---------------- | -- |  | ----- | -
|                                     |  | 2008 |    | 2007 |   | DollarVariance |  | PercentageChange |   
|Wages, salaries and related expenses |  | $    | 28 |      | $ | 18             |  | $                | 10 |  | 55.6  | %
|Stock-based compensation             |  |      | 12 |      |   | 5              |  |                  | 7  |  | 140.0 | %
|Professional services                |  |      | 19 |      |   | 15             |  |                  | 4  |  | 26.7  | %
|Short-term incentive compensation    |  |      | 8  |      |   | 6              |  |                  | 2  |  | 33.3  | %
|Other                                |  |      | 13 |      |   | 11             |  |                  | 2  |  | 18.2  | %
|                                     |  |      |    |      |   |                |  |                  |    |  |       |  
|Total General and Administrative     |  | $    | 80 |      | $ | 55             |  | $                | 25 |  | 45.5  | %
|                                     |  |      |    |      |   |                |  |                  |    |  |       |  



45



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##### Table of Contents

Employee wages, salaries and related expenses have increased $10 million primarily due to the additional
staffing added as a result of the on-going growth of the company.



Stock-based compensation has increased $7 million primarily due to additional awards granted in 2008 and higher costs related to the performance share program. The performance share costs are related to additional units awarded and the
increase in the market price of CNX Gas common stock in 2008.



Professional services have increased $4 million primarily due to fees related to completing the registration of emission offset credits on the Chicago Climate Exchange. Professional services also increased due to various administrative
projects which have occurred throughout both years, none of which were individually significant.



The short-term incentive compensation program is designed to increase compensation to eligible employees when CNX Gas reaches predetermined targets for
production, unit cost and safety. Incentive compensation expense increased $2 million when compared to the prior year due to improved performance relative to the targets.



The $2 million increase in other costs is related to various transactions that occurred throughout both years, none of which were
individually material.



Depreciation, depletion and
amortization have increased due to the following items:



|                                               |  |      |    |      |   |                |  |                  |    |  |      |  
|---------------------------------------------- |  | ---- | -- | ---- | - | -------------- |  | ---------------- | -- |  | ---- | -
|                                               |  | 2008 |    | 2007 |   | DollarVariance |  | PercentageChange |   
|Production                                     |  | $    | 50 |      | $ | 31             |  | $                | 19 |  | 61.3 | %
|Gathering                                      |  |      | 19 |      |   | 17             |  |                  | 2  |  | 11.8 | %
|Other                                          |  |      | 1  |      |   | 1              |  |                  |   |  |     |  
|                                               |  |      |    |      |   |                |  |                  |    |  |      |  
|Total Depreciation, Depletion and Amortization |  | $    | 70 |      | $ | 49             |  | $                | 21 |  | 42.9 | %
|                                               |  |      |    |      |   |                |  |                  |    |  |      |  



The $19 million
increase in production-related depreciation, depletion and amortization was primarily due to higher volumes combined with an increase in the units of production rates in the year-to-year comparison. 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 $2 million due to additional assets placed in service after December 31, 2007.



Other depreciation remained consistent in the year-to-year comparison.



Interest expense increased due to the following items:



|                       |  |      |   |      |   |                |  |                  |   |  |       |  
|---------------------- |  | ---- | - | ---- | - | -------------- |  | ---------------- | - |  | ----- | -
|                       |  | 2008 |   | 2007 |   | DollarVariance |  | PercentageChange |  
|Revolver               |  | $    | 1 |      | $ |               |  | $                | 1 |  | 100.0 | %
|Capitalized lease      |  |      | 5 |      |   | 5              |  |                  |  |  |      |  
|Miscellaneous          |  |      | 2 |      |   | 1              |  |                  | 1 |  | 100.0 | %
|                       |  |      |   |      |   |                |  |                  |   |  |       |  
|Total Interest Expense |  | $    | 8 |      | $ | 6              |  | $                | 2 |  | 33.3  | %
|                       |  |      |   |      |   |                |  |                  |   |  |       |  



Interest expense
increased $1 million in the year-to-year comparison due to outstanding principal on the revolving credit facility. There were no outstanding principal amounts on the facility in 2007.



Interest on capital leases remained consistent in the year-to-year comparison.



46



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##### Table of Contents

Miscellaneous interest increased $1 million due to various transactions that occurred throughout both
years, none of which were individually material.



Income Taxes



|                             |  |      |      |   |      |   |      |          |  |   |                  |   |  |   |      |  
|---------------------------- |  | ---- | ---- | - | ---- | - | ---- | -------- |  | - | ---------------- | - |  | - | ---- | -
|                             |  | 2008 |      |   | 2007 |   |      | Variance |  |   | PercentageChange |  
|Earnings Before Income Taxes |  | $    | 393  |   |      | $ | 221  |          |  | $ | 172              |   |  | $ | 77.8 | %
|Tax Expense                  |  | $    | 154  |   |      | $ | 85   |          |  | $ | 69               |   |  | $ | 81.2 | %
|Effective Income Tax Rate    |  |      | 39.1 | % |      |   | 38.5 | %        |  |   | 0.6              | % |  |   |      |  



CNX Gas
effective tax rate increased in the year-to-year comparison primarily due to changes in the net effect of state income taxes. See Note 5 Income Taxes of the Consolidated Financial Statements for additional details.



Year Ended December 31, 2007 compared with Year Ended December 31, 2006

(Dollars reported in millions)



Net Income



Net income changed primarily due to the following items:



|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|-------------------------------------------------- |  | ---- | --- | ---- | - | -------------- |  | - | ---------------- | - |  | ----- | --
|                                                   |  | 2007 |     | 2006 |   | DollarVariance |  |   | PercentageChange |  
|Revenue and Other Income:                          |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Outside Sales                                      |  | $    | 405 |      | $ | 385            |  | $ | 20               |   |  | 5.2   | % 
|Related Party Sales                                |  |      | 11  |      |   | 8              |  |   | 3                |   |  | 37.5  | % 
|Royalty Interest Gas Sales                         |  |      | 46  |      |   | 51             |  |   | (5               | ) |  | (9.8  | )%
|Purchased Gas Sales                                |  |      | 8   |      |   | 44             |  |   | (36              | ) |  | (81.8 | )%
|Other Income                                       |  |      | 9   |      |   | 27             |  |   | (18              | ) |  | (66.7 | )%
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Revenue and Other Income                     |  |      | 479 |      |   | 515            |  |   | (36              | ) |  | (7.0  | )%
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Costs and Expenses:                                |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Lifting Costs                                      |  |      | 38  |      |   | 33             |  |   | 5                |   |  | 15.2  | % 
|Gathering and Compression Costs                    |  |      | 62  |      |   | 58             |  |   | 4                |   |  | 6.9   | % 
|Royalty Interest Gas Costs                         |  |      | 40  |      |   | 42             |  |   | (2               | ) |  | (4.8  | )%
|Purchased Gas Costs                                |  |      | 7   |      |   | 45             |  |   | (38              | ) |  | (84.4 | )%
|Other                                              |  |      | 1   |      |   | 2              |  |   | (1               | ) |  | (50.0 | )%
|General and Administrative                         |  |      | 55  |      |   | 39             |  |   | 16               |   |  | 41.0  | % 
|Depreciation, Depletion and Amortization           |  |      | 49  |      |   | 38             |  |   | 11               |   |  | 28.9  | % 
|Interest Expense                                   |  |      | 6   |      |   | 1              |  |   | 5                |   |  | 500.0 | % 
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Costs and Expenses                           |  |      | 258 |      |   | 258            |  |   |                 |   |  |      |   
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Earnings Before Income Taxes and Minority Interest |  |      | 221 |      |   | 257            |  |   | (36              | ) |  | (14.0 | )%
|Income Taxes                                       |  |      | 85  |      |   | 97             |  |   | (12              | ) |  | (12.4 | )%
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Net Income                                         |  | $    | 136 |      | $ | 160            |  | $ | (24              | ) |  | (15.0 | )%
|                                                   |  |      |     |      |   |                |  |   |                  |   |  |       |   



Net income for 2007
was lower primarily due to deferred production resulting from the July 2007 Buchanan mine incident, lower insurance proceeds in 2007 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.



47



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##### Table of Contents

Revenue and Other Income



Revenue and other income decreased due to the following items:



|                               |  |      |     |      |   |                |  |   |                  |   |  |       |   
|------------------------------ |  | ---- | --- | ---- | - | -------------- |  | - | ---------------- | - |  | ----- | --
|                               |  | 2007 |     | 2006 |   | DollarVariance |  |   | PercentageChange |  
|Revenue and Other Income:      |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Outside Sales                  |  | $    | 405 |      | $ | 385            |  | $ | 20               |   |  | 5.2   | % 
|Related Party Sales            |  |      | 11  |      |   | 8              |  |   | 3                |   |  | 37.5  | % 
|Royalty Interest Gas Sales     |  |      | 46  |      |   | 51             |  |   | (5               | ) |  | (9.8  | )%
|Purchased Gas Sales            |  |      | 8   |      |   | 44             |  |   | (36              | ) |  | (81.8 | )%
|Other Income                   |  |      | 9   |      |   | 27             |  |   | (18              | ) |  | (66.7 | )%
|                               |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Revenue and Other Income |  | $    | 479 |      | $ | 515            |  | $ | (36              | ) |  | (7.0  | )%
|                               |  |      |     |      |   |                |  |   |                  |   |  |       |   



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 2007 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 2007.



|                              |  |      |      |      |   |          |  |                  |      |  |     |  
|----------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- | ---- |  | --- | -
|                              |  | 2007 |      | 2006 |   | Variance |  | PercentageChange |     
|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 year ended December 31, 2007 at an average price of $8.01 per Mcf. In 2006,
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 July 2007 Buchanan Mine issue at CONSOL Energy.



|                                         |  |      |      |      |   |          |  |   |                  |   |  |      |   
|---------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ---- | --
|                                         |  | 2007 |      | 2006 |   | Variance |  |   | PercentageChange |  
|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.



|                                  |  |      |      |      |   |          |  |   |                  |   |  |       |   
|--------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ----- | --
|                                  |  | 2007 |      | 2006 |   | Variance |  |   | PercentageChange |  
|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 2007 represent volumes of gas we sell at market prices that were purchased from third party producers, less our gathering fees. In 2006, purchased gas sales and volumes represented



48



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##### Table of Contents

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 income consists of the following items:



|                                 |  |      |   |      |   |                |  |   |                  |   |  |        |   
|-------------------------------- |  | ---- | - | ---- | - | -------------- |  | - | ---------------- | - |  | ------ | --
|                                 |  | 2007 |   | 2006 |   | DollarVariance |  |   | PercentageChange |  
|Royalty Income                   |  | $    |  |      | $ | 10             |  | $ | (10              | ) |  | (100.0 | )%
|Business Interruption Insurance  |  |      | 2 |      |   | 10             |  |   | (8               | ) |  | (80.0  | )%
|Third Party Gathering Revenue    |  |      | 1 |      |   | 1              |  |   |                 |   |  |       |   
|Interest Income                  |  |      | 4 |      |   | 4              |  |   |                 |   |  |       |   
|Equity in Earnings of Affiliates |  |      | 2 |      |   | 1              |  |   | 1                |   |  | 100.0  | % 
|Miscellaneous Income             |  |      |  |      |   | 1              |  |   | (1               | ) |  | (100.0 | )%
|                                 |  |      |   |      |   |                |  |   |                  |   |  |        |   
|Total Other Income               |  | $    | 9 |      | $ | 27             |  | $ | (18              | ) |  | (66.7  | )%
|                                 |  |      |   |      |   |                |  |   |                  |   |  |        |   



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 2006, the volumes were not available nor were they considered in the 2006 reserve report. In 2007, 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 2007. 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 consistent in the year-to-year comparison.



Interest income remained consistent in the year-to-year comparison



Equity in earnings of affiliates increased $1 million related
to activities at Knox Energy, LLC in which CNX Gas held an equity interest.



Miscellaneous income decreased $1 million due to various transactions that occurred throughout both years, none of which were individually material.



Costs and Expenses



Costs and expenses decreased due to the following items:



|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|---------------------------------------- |  | ---- | --- | ---- | - | -------------- |  | - | ---------------- | - |  | ----- | --
|                                         |  | 2007 |     | 2006 |   | DollarVariance |  |   | PercentageChange |  
|Costs and Expenses:                      |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Lifting Costs                            |  | $    | 38  |      | $ | 33             |  | $ | 5                |   |  | 15.2  | % 
|Gathering and Compression Costs          |  |      | 62  |      |   | 58             |  |   | 4                |   |  | 6.9   | % 
|Royalty Interest Gas Costs               |  |      | 40  |      |   | 42             |  |   | (2               | ) |  | (4.8  | )%
|Purchased Gas Costs                      |  |      | 7   |      |   | 45             |  |   | (38              | ) |  | (84.4 | )%
|Other                                    |  |      | 1   |      |   | 2              |  |   | (1               | ) |  | (50.0 | )%
|General and Administrative               |  |      | 55  |      |   | 39             |  |   | 16               |   |  | 41.0  | % 
|Depreciation, Depletion and Amortization |  |      | 49  |      |   | 38             |  |   | 11               |   |  | 28.9  | % 
|Interest Expense                         |  |      | 6   |      |   | 1              |  |   | 5                |   |  | 500.0 | % 
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   
|Total Costs and Expenses                 |  | $    | 258 |      | $ | 258            |  | $ |                 |   |  |      |   
|                                         |  |      |     |      |   |                |  |   |                  |   |  |       |   



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Total costs and expenses remained consistent in the year-to-year comparison.



|                                |  |      |      |      |   |          |  |                  |      |  |      |  
|------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- | ---- |  | ---- | -
|                                |  | 2007 |      | 2006 |   | Variance |  | PercentageChange |     
|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 2007 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.



|                                                  |  |      |      |      |   |          |  |                  |      |  |     |  
|------------------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | ---------------- | ---- |  | --- | -
|                                                  |  | 2007 |      | 2006 |   | Variance |  | PercentageChange |     
|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.



|                                         |  |      |      |      |   |          |  |   |                  |   |  |      |   
|---------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ---- | --
|                                         |  | 2007 |      | 2006 |   | Variance |  |   | PercentageChange |  
|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.



|                                      |  |      |      |      |   |          |  |   |                  |   |  |       |   
|------------------------------------- |  | ---- | ---- | ---- | - | -------- |  | - | ---------------- | - |  | ----- | --
|                                      |  | 2007 |      | 2006 |   | Variance |  |   | PercentageChange |  
|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 2007 represent volumes of gas we sold at market prices that were purchased from third party producers, less our gathering fees. In 2006, 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 $1 million due to various transactions that occurred throughout both years, none of which
were individually material.



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##### Table of Contents

General and Administrative expenses increased due to the following items:



|                                 |  |      |    |      |   |                |  |                  |    |  |       |  
|-------------------------------- |  | ---- | -- | ---- | - | -------------- |  | ---------------- | -- |  | ----- | -
|                                 |  | 2007 |    | 2006 |   | DollarVariance |  | PercentageChange |   
|Professional Fees                |  | $    | 16 |      | $ | 9              |  | $                | 7  |  | 77.8  | %
|Employee Wages and Related Costs |  |      | 19 |      |   | 17             |  |                  | 2  |  | 11.8  | %
|Facilities                       |  |      | 5  |      |   | 3              |  |                  | 2  |  | 66.7  | %
|Stock Based Compensation         |  |      | 5  |      |   | 4              |  |                  | 1  |  | 25.0  | %
|Short Term Incentive             |  |      | 6  |      |   | 5              |  |                  | 1  |  | 20.0  | %
|Other                            |  |      | 4  |      |   | 1              |  |                  | 3  |  | 300.0 | %
|                                 |  |      |    |      |   |                |  |                  |    |  |       |  
|Total                            |  | $    | 55 |      | $ | 39             |  | $                | 16 |  | 41.0  | %
|                                 |  |      |    |      |   |                |  |                  |    |  |       |  



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 2006, these
costs were capitalized as part of the implementation, however these costs are expensed in 2007.



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 went
from 192 employees on December 31, 2006 to 281 employees on December 31, 2007.



The increase in Facilities in 2007 related to the establishment of a new company headquarters, various other offices associated with the continued growth of the company, and our entrance into other regions.



Short Term Incentive and Stock Based Compensation costs have
increased also as a result of the on-going growth of the company.



The increase in Other costs was due primarily to increased insurance premiums as well as various other items that were not individually significant.



Depreciation, depletion and amortization increased due to the following items:



|                                               |  |      |    |      |   |                |  |                  |    |  |      |  
|---------------------------------------------- |  | ---- | -- | ---- | - | -------------- |  | ---------------- | -- |  | ---- | -
|                                               |  | 2007 |    | 2006 |   | DollarVariance |  | PercentageChange |   
|Production                                     |  | $    | 31 |      | $ | 25             |  | $                | 6  |  | 24.0 | %
|Gathering                                      |  |      | 18 |      |   | 13             |  |                  | 5  |  | 38.5 | %
|                                               |  |      |    |      |   |                |  |                  |    |  |      |  
|Total Depreciation, Depletion and Amortization |  | $    | 49 |      | $ | 38             |  | $                | 11 |  | 28.9 | %
|                                               |  |      |    |      |   |                |  |                  |    |  |      |  



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 year-to-year. 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.



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Income Taxes



|                             |  |      |      |   |      |   |      |          |  |   |                  |   |  |       |   
|---------------------------- |  | ---- | ---- | - | ---- | - | ---- | -------- |  | - | ---------------- | - |  | ----- | --
|                             |  | 2007 |      |   | 2006 |   |      | Variance |  |   | PercentageChange |  
|Earnings Before Income Taxes |  | $    | 221  |   |      | $ | 257  |          |  | $ | (36              | ) |  | (14.0 | )%
|Tax Expense                  |  | $    | 85   |   |      | $ | 97   |          |  | $ | (12              | ) |  | (12.4 | )%
|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. See Note 5 of the Notes to the Consolidated Financial Statements for additional details.



Critical Accounting Policies



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.



Derivative Instruments



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. We 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.



Stock-Based Compensation



CNX Gas uses the provisions of Statement of Financial
Accounting Standards No. 123R, Share-Based Payments (SFAS No. 123R). As of December 31, 2008, we have issued three types of share based payments awards: options, restricted stock units, and performance stock units. The
Black-Scholes option pricing model is used to determine fair value of stock options at the grant date. Various inputs are utilized in the Black-Scholes pricing model, such as:



| |  |  | stock price on measurement date,
| | - |  | --------------------------------



| |  |  | exercise price defined in the award,
| | - |  | ------------------------------------



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| |  |  | expected dividend yield based on historical trend of dividend payouts,
| | - |  | ----------------------------------------------------------------------



| |  |  | risk-free interest rate based on a zero-coupon treasury bond rate,
| | - |  | ------------------------------------------------------------------



| |  |  | expected term based on historical grant and exercise behavior, and
| | - |  | ------------------------------------------------------------------



| |  |  | expected volatility based on historic and implied stock price volatility of CONSOL Energy stock and public peer group stock.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------



These factors can significantly impact the value of stock options expense
recognized over the requisite service period of option holders.



The fair value of each restricted stock unit awarded is equivalent to the closing market price of a share of our companys stock. The fair value of each performance share unit is determined by the underlying share price of our company
stock on the valuation date and managements estimate of the probability that the performance conditions required for vesting well be achieved.



Successful Efforts Accounting



We use the successful efforts method to account for our gas exploration and production activities. Under this method, costs of property
acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the
determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. 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 gas exploration and production activities.



Estimated Net Recoverable Reserves



CNX Gas uses the successful efforts method to account for our 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 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.



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Contingencies



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 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.



Income Taxes



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, 2008, CNX Gas had deferred tax liabilities in excess of
deferred tax assets of approximately $386 million. 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. The implementation of FIN No. 48, did not materially
impact the financial position of CNX Gas. As of December 31, 2008, CNX Gas does not anticipate a significant change in our uncertain tax positions or unrecognized tax benefits.



Asset Retirement Obligations



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.



Liquidity and Capital Resources



CNX Gas has satisfied our working capital requirements and funded our capital expenditures with cash from operations and our $200 million credit facility.
Our credit agreement provides for a revolving credit facility with an initial aggregate outstanding principal amount of up to $200 million (with the ability to request an increase in the aggregate outstanding principal amount up to $300 million),
including borrowings and letters of credit. We



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use the credit facility 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, however the credit agreement does contain a negative pledge provision providing that our assets cannot be used to secure any other obligation. Fees and
interest rate spreads are based on the percentage of facility utilization, measured quarterly. The facility includes a minimum interest coverage ratio of no less than 3.00 to 1.00, measured quarterly. The interest coverage ratio was 77.29 to 1.00 at
December 31, 2008. The facility also includes a maximum leverage ratio of no more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.32 to 1.00 at December 31, 2008. Affirmative and negative covenants in the facility limit our
ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. At December 31, 2008, the facility had approximately $73 million of borrowings outstanding, and $15 million of
letters of credit outstanding, leaving $112 million of unused capacity.



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 $250 million. 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.



Currently, there is an unprecedented uncertainty in
the financial markets. The uncertainty in the market brings additional potential risks to CNX Gas. The risks include additional declines in our stock price, less availability and higher costs of additional credit, potential counterparty defaults,
and further commercial bank failures. Although the majority of the financial institutions in our bank group appear to be strong, there are some that have been and could be considered take-over candidates. Although we have no indication that any such
transactions would impact our current credit facility, the possibility does exist. Financial market disruptions may impact our ability to collect trade receivables. The credit worthiness of our customers is constantly monitored by CNX Gas. We
believe that our current group of customers are sound and represent no abnormal business risk.



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
$207 million at December 31, 2008. The ineffective portion of the changes in the fair value of these contracts was insignificant for the years ended December 31, 2008, 2007 and 2006.



Cash Flows (in millions)



|                                                |  |      |      |   |      |   |      |        |  |   |      |  
|----------------------------------------------- |  | ---- | ---- | - | ---- | - | ---- | ------ |  | - | ---- | -
|                                                |  | 2008 |      |   | 2007 |   |      | Change | 
|Cash provided by operating activities           |  | $    | 447  |   |      | $ | 272  |        |  | $ | 175  |  
|Cash used in investing activities               |  | $    | (559 | ) |      | $ | (354 | )      |  | $ | (205 | )
|Cash provided by (used in) financing activities |  | $    | 82   |   |      | $ | 7    |        |  | $ | 75   |  



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, 2008, we entered into hedging agreements covering 41.9 Bcf and 23.3 Bcf for 2009 and 2010, respectively.



| |  |  | Cash provided by operating activitiesincreased primarily due to increased production and higher realized prices. These increases are partially offset by
increased operating costs and various other working capital requirements.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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| |  |  | Cash used in investing activities increased primarily due to higher capital expenditures, which is a result of our expanded drilling program. Current year
expenditures also included $36 million for the acquisition of the remaining interest in Knox Energy that CNX Gas did not previously own and $19 million for the acquisition of several leases on gas wells from KIS Oil & Gas Inc., as detailed
further in Note 2 of the Notes to the Consolidated Financial Statements.
| | - |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



| |  |  | Cash provided by financing activitiesincreased primarily due to proceeds of approximately $73 million from the credit facility during the year ended
December 31, 2008. There were no borrowings under the facility in the year ended December 31, 2007.
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Contractual Commitments



The following is a summary of our significant contractual obligations at December 31, 2008 (in millions). We estimate payments related to these
items, net of any applicable reimbursements, at December 31, 2008 to be as follows:



|                                            |  |              |         |           |   |           |  |                  |        |       |   |         |  |   |        
|------------------------------------------- |  | ------------ | ------- | --------- | - | --------- |  | ---------------- | ------ | ----- | - | ------- |  | - | -------
|(In thousands)                              |  | Within1 Year |         | 1-3 Years |   | 3-5 Years |  | More than 5Years |        | Total
|Short Term Debt ObligationsRevolver        |  | $            | 72,700  |           | $ |          |  | $                |       |       | $ |        |  | $ | 72,700 
|Long Term Debt Obligations                  |  |              | 5,558   |           |   | 15,815    |  |                  |       |       |   | 621     |  |   | 21,994 
|Capital Lease Obligation                    |  |              | 9,191   |           |   | 16,134    |  |                  | 14,928 |       |   | 57,754  |  |   | 98,007 
|Operating Lease Obligations                 |  |              | 2,443   |           |   | 3,931     |  |                  | 2,786  |       |   | 2,208   |  |   | 11,368 
|Other Long-term Liabilities:                |  |              |         |           |   |           |  |                  |        |       |   |         |  |   |        
|Gas Firm Transportation Obligations         |  |              | 19,449  |           |   | 36,494    |  |                  | 32,235 |       |   | 239,196 |  |   | 327,374
|Other Long-term Liabilities(a)              |  |              | 7,847   |           |   | 3,933     |  |                  |       |       |   | 22,642  |  |   | 34,422 
|Well Plugging Liabilities                   |  |              |        |           |   | 104       |  |                  | 419    |       |   | 6,878   |  |   | 7,401  
|Post Retirement Benefits Other than Pension |  |              | 154     |           |   | 332       |  |                  | 324    |       |   | 2,072   |  |   | 2,882  
|Purchase Obligations                        |  |              | 2,728   |           |   | 4,769     |  |                  |       |       |   |        |  |   | 7,497  
|                                            |  |              |         |           |   |           |  |                  |        |       |   |         |  |   |        
|Total Contractual Obligations(b)            |  | $            | 120,070 |           | $ | 81,512    |  | $                | 50,692 |       | $ | 331,371 |  | $ | 583,645
|                                            |  |              |         |           |   |           |  |                  |        |       |   |         |  |   |        



|(a) | This item includes legal contingencies and other liabilities.
|--- | -------------------------------------------------------------

|(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.



$200 million Credit Facility



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 million with the ability to request an increase in the aggregate outstanding principal amount up to $300
million, 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, 2008, there was approximately $73 million of outstanding borrowings and $15 million related to outstanding letters of credit, leaving $112 million of unused capacity.



Our ability to borrow and obtain letters of credit under the credit agreement is limited to a borrowing base. The required
number of lenders determine this borrowing base by calculating a loan value of CNX Gas proved reserves and reducing that number by an equity cushion. The current borrowing base is in excess of $200 million.



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##### Table of Contents

Stockholders Equity



CNX Gas had stockholders equity of $1,385 million at December 31, 2008 and $1,023 million at December 31,
2007. The increase was primarily attributable to net income for the year ended December 31, 2008 and unrealized hedging gains. See Consolidated Statements of Stockholders Equity in the Audited Consolidated Financial Statements in
Item 8 of this Form 10-K.



Off-Balance Sheet
Arrangements



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.



Recent Accounting Pronouncements



In May 2008, The Financial Accounting Standards Board (FASB) issued Statement No. 162, The Hierarchy of Generally Accepted Accounting
Principles. The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for selecting accounting principles to be used in preparing financial statements that are presented in conformity with
U.S. generally accepted accounting principles (GAAP) for nongovernmental entities. Statement 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting
accounting principles for financial statements that are presented in conformity with GAAP. Statement 162 is effective 60 days following the SECs approval of the Public Company Accounting Oversight Board Auditing amendments to AU
Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. We do not expect this guidance to have a significant impact on CNX Gas.



In March 2008, The Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement 133 (SFAS 161). The new standard is intended to improve financial reporting about
derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entitys financial positions, results of operations and cash flows. The new standard also improves
transparency about how and why a company uses derivative instruments and how derivative instruments and related hedged items are accounted for under Statement 133. It is effective for financial statements issued for fiscal years and interim periods
beginning after November 15, 2008, with early application encouraged. CNX Gas management is currently assessing the new disclosure requirements required by SFAS 161.



In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards
No. 141(R), 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.



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##### Table of Contents

|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 mitigates CNX Gass exposure 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, or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.



For a summary of accounting policies related to derivative instruments, see
Note 1 of the Notes to the Consolidated Financial Statements.



Sensitivity analyses of the incremental effects on pre-tax income for the year ended December 31, 2008 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2008 are provided
in the following table:



|                  |  |                                                              |      |     |   |      
|----------------- |  | ------------------------------------------------------------ | ---- | --- | - | -----
|                  |  | Incremental DecreaseAssuming aHypothetical PriceIncrease of:
|                  |  | 10%                                                          |      | 25%
|                  |  | (Dollars in millions)                                       
|Pre-Tax Income(1) |  | $                                                            | 40.3 |     | $ | 102.6



|(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. CNX Gas entered into derivative instruments to convert the market prices related to portions of the 2009 through 2010 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. As of December 31, 2008, the fair value of these contracts was a net gain of $119 million (net of $77 million deferred tax). We will continually evaluate the portfolio of derivative commodity
instruments and adjust the strategy to anticipated market conditions and risks accordingly.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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##### Table of Contents

Hedging Volumes



As of December 31, 2008, our hedged volumes for the periods indicated are as follows:



|                                 |  |                            |            |                           |   |                                |  |                               |            |            |   |           |  |   |           
|-------------------------------- |  | -------------------------- | ---------- | ------------------------- | - | ------------------------------ |  | ----------------------------- | ---------- | ---------- | - | --------- |  | - | ----------
|                                 |  | Three MonthsEndedMarch 31, |            | Three MonthsEndedJune 30, |   | Three MonthsEndedSeptember 30, |  | Three MonthsEndedDecember 31, |            | Total Year
|2009 Fixed Price Volumes         |  |                            |            |                           |   |                                |  |                               |            |            |   |           |  |   |           
|Hedged Mcf                       |  |                            | 10,670,103 |                           |   | 10,631,443                     |  |                               | 10,670,103 |            |   | 9,884,021 |  |   | 41,855,670
|Weighted Average Hedge Price/Mcf |  | $                          | 9.85       |                           | $ | 9.73                           |  | $                             | 9.74       |            | $ | 9.64      |  | $ | 9.74      
|                                 |  |                            |            |                           |  
|2010 Fixed Price Volumes         |  |                            |            |                           |   |                                |  |                               |            |            |   |           |  |   |           
|Hedged Mcf                       |  |                            | 9,278,351  |                           |   | 7,974,227                      |  |                               | 5,082,474  |            |   | 943,299   |  |   | 23,278,351
|Weighted Average Hedge Price/Mcf |  | $                          | 9.70       |                           | $ | 9.54                           |  | $                             | 9.70       |            | $ | 8.28      |  | $ | 9.59      



CNX Gas is exposed to
credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review. All of the counterparties to CNX Gas natural gas derivative instruments also participate in CNX Gas
revolving credit facility. The Company has not experienced any issues of non performance by derivative counterparties. See the Liquidity and Capital Resources section of this Annual Report for further discussion of current capital markets.



CNX Gas interest expense is sensitive to changes in the
general level of interest rates in the United States. At December 31, 2008, CNX Gas had $83.1 million aggregate principal amount of debt outstanding under fixed-rate instruments and $72.7 million aggregate principal amount of debt outstanding
under variable-rate instruments. CNX Gas primary exposure to market risk is for changes in interest rates related to the revolving credit facility, under which there were $72.7 million of borrowings outstanding at December 31, 2008. CNX
Gas revolving credit facility bore interest at a weighted average rate of 3.51% per annum during the year ended December 31, 2008. Due to the level of borrowings against this facility and the low weighted average interest rate in the
year ended December 31, 2008, a 100 basis-point increase in the average rate for CNX Gas revolving credit facility would not have significantly decreased net income for the period.



All CNX Gas transactions are denominated in U.S. dollars, and as a result, we
do not have any exposure to currency exchange-rate risks.



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|Item 8. | Financial Statements and Supplementary Data
|------- | -------------------------------------------



|                                                                                                     |  |     
|---------------------------------------------------------------------------------------------------- |  | ----
|                                                                                                     |  | Page
|Financial Statements                                                                                 |  |     
|Reports of Independent Registered Public Accounting Firms                                           |  | 61  
|Consolidated Statements of Income for the years ended December 31, 2008, 2007 and 2006               |  | 63  
|Consolidated Balance Sheets as of December 31, 2008 and 2007                                         |  | 64  
|Consolidated Statements of Stockholders Equity for the years ended December 31, 2008, 2007 and
2006 |  | 65  
|Consolidated Statements of Cash Flows for the years ended December 31, 2008, 2007 and 2006           |  | 66  
|Notes to Audited Financial Statements                                                                |  | 67  



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##### Table of Contents

Report of Independent Registered Public Accounting Firm



To the Board of Directors and Stockholders of CNX Gas Corporation



We have audited the accompanying consolidated balance sheet of CNX Gas
Corporation (and Subsidiaries) as of December 31, 2008, and the related consolidated statements of income, stockholders equity, and cash flows for the year then ended. These financial statements are the responsibility of the
Companys management. Our responsibility is to express an opinion on these financial statements based on our audit.



We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we
plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for
our opinion.



In our opinion, the financial statements referred
to above present fairly, in all material respects, the consolidated financial position of CNX Gas Corporation (and Subsidiaries) at December 31, 2008, and the consolidated results of their operations and their cash flows for the year then
ended, in conformity with U.S. generally accepted accounting principles.



As discussed in Note 12 to the consolidated financial statements, during the year ended December 31, 2008, the Company adopted the measurement provisions of Statement of Financial Accounting Standards
No. 158, Employers Accounting for Defined Benefit Pension and Other Postretirement Plansan amendment of FASB Statements No. 87, 88, 106, and 132(R).



We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), CNX
Gas Corporations internal control over financial reporting as of December 31, 2008, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated February 17, 2009 expressed an unqualified opinion thereon.



/s/    Ernst & Young LLP



Pittsburgh, PA

February 17, 2009



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##### Table of Contents

Report of Independent Registered Public Accounting Firm



To the Board of Directors and Stockholders of CNX Gas Corporation:



In our opinion, the consolidated balance sheet as of December 31, 2007
and the related consolidated statements of income, stockholders equity and cash flows for each of two years in the period ended December 31, 2007 present fairly, in all material respects, the financial position of CNX Gas Corporation and
its subsidiaries (CNX Gas) at December 31, 2007, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2007, in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the financial statement schedule included in Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the
related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of CNX Gas management. Our responsibility is to express an opinion on these financial statements and financial
statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes 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. We believe that our audits provide a reasonable basis for our opinion.



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.



/s/ PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania

February 15,
2008



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##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)



|                                                      |  |                                  |             |      |   |             |  |   |            
|----------------------------------------------------- |  | -------------------------------- | ----------- | ---- | - | ----------- |  | - | -----------
|                                                      |  | For the Years Ended December 31,
|                                                      |  | 2008                             |             | 2007 |   | 2006       
|Revenue and Other Income:                             |  |                                  |             |      |   |             |  |   |            
|Outside Sales                                         |  | $                                | 678,793     |      | $ | 404,835     |  | $ | 385,056    
|Related Party Sales                                   |  |                                  | 9,532       |      |   | 11,618      |  |   | 8,490      
|Royalty Interest Gas Sales                            |  |                                  | 79,302      |      |   | 46,586      |  |   | 51,054     
|Purchased Gas Sales                                   |  |                                  | 8,464       |      |   | 7,628       |  |   | 43,973     
|Other Income                                          |  |                                  | 13,330      |      |   | 8,815       |  |   | 26,264     
|                                                      |  |                                  |             |      |   |             |  |   |            
|Total Revenue and Other Income                        |  |                                  | 789,421     |      |   | 479,482     |  |   | 514,837    
|                                                      |  |                                  |             |      |   |             |  |   |            
|Costs and Expenses:                                   |  |                                  |             |      |   |             |  |   |            
|Lifting Costs                                         |  |                                  | 67,653      |      |   | 38,721      |  |   | 33,357     
|Gathering and Compression Costs                       |  |                                  | 83,752      |      |   | 61,798      |  |   | 58,102     
|Royalty Interest Gas Costs                            |  |                                  | 74,041      |      |   | 40,011      |  |   | 41,998     
|Purchased Gas Costs                                   |  |                                  | 8,175       |      |   | 7,162       |  |   | 44,843     
|Other                                                 |  |                                  | 4,995       |      |   | 1,759       |  |   | 2,060      
|General and Administrative                            |  |                                  | 80,246      |      |   | 54,825      |  |   | 39,168     
|Depreciation, Depletion and Amortization              |  |                                  | 70,010      |      |   | 48,961      |  |   | 37,999     
|Interest Expense                                      |  |                                  | 7,820       |      |   | 5,606       |  |   | 870        
|                                                      |  |                                  |             |      |   |             |  |   |            
|Total Costs and Expenses                              |  |                                  | 396,692     |      |   | 258,843     |  |   | 258,397    
|                                                      |  |                                  |             |      |   |             |  |   |            
|Earnings Before Income Taxes                          |  |                                  | 392,729     |      |   | 220,639     |  |   | 256,440    
|Income Taxes                                          |  |                                  | 153,656     |      |   | 84,961      |  |   | 96,573     
|                                                      |  |                                  |             |      |   |             |  |   |            
|Net Income                                            |  | $                                | 239,073     |      | $ | 135,678     |  | $ | 159,867    
|                                                      |  |                                  |             |      |   |             |  |   |            
|Earnings per share:                                   |  |                                  |             |      |   |             |  |   |            
|Basic                                                 |  | $                                | 1.58        |      | $ | 0.90        |  | $ | 1.06       
|                                                      |  |                                  |             |      |   |             |  |   |            
|Diluted                                               |  | $                                | 1.58        |      | $ | 0.90        |  | $ | 1.06       
|                                                      |  |                                  |             |      |   |             |  |   |            
|Weighted Average Number of Common Shares Outstanding: |  |                                  |             |      |   |             |  |   |            
|Basic                                                 |  |                                  | 150,947,516 |      |   | 150,886,433 |  |   | 150,845,518
|                                                      |  |                                  |             |      |   |             |  |   |            
|Dilutive                                              |  |                                  | 151,331,953 |      |   | 151,133,520 |  |   | 151,017,456
|                                                      |  |                                  |             |      |   |             |  |   |            



The accompanying notes
are an integral part of these consolidated financial statements.



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CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS

(Dollars in thousands, except per share data)



|                                                                                                                                                                                 |  |              |           |      |   |          
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ------------ | --------- | ---- | - | ---------
|                                                                                                                                                                                 |  | December 31,
|                                                                                                                                                                                 |  | 2008         |           | 2007
|ASSETS                                                                                                                                                                           |  |              |           |      |   |          
|Current Assets:                                                                                                                                                                  |  |              |           |      |   |          
|Cash and Cash Equivalents                                                                                                                                                        |  | $            | 1,926     |      | $ | 32,048   
|Accounts and Notes Receivable:                                                                                                                                                   |  |              |           |      |   |          
|Trade                                                                                                                                                                            |  |              | 61,764    |      |   | 38,680   
|Related Parties                                                                                                                                                                  |  |              |          |      |   | 1,022    
|Other Receivables                                                                                                                                                                |  |              | 3,080     |      |   | 1,406    
|Recoverable Income Taxes                                                                                                                                                         |  |              | 30,302    |      |   | 972      
|Derivatives                                                                                                                                                                      |  |              | 150,564   |      |   | 10,711   
|Other                                                                                                                                                                            |  |              | 2,222     |      |   | 3,148    
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Current Assets                                                                                                                                                             |  |              | 249,858   |      |   | 87,987   
|Property, Plant and Equipment:                                                                                                                                                   |  |              |           |      |   |          
|Property, Plant and Equipment                                                                                                                                                    |  |              | 2,111,383 |      |   | 1,509,060
|LessAccumulated Depreciation, Depletion and Amortization                                                                                                                        |  |              | 322,470   |      |   | 254,154  
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Property, Plant and EquipmentNet                                                                                                                                          |  |              | 1,788,913 |      |   | 1,254,906
|Other Assets:                                                                                                                                                                    |  |              |           |      |   |          
|Investment in Affiliates                                                                                                                                                         |  |              | 25,204    |      |   | 28,284   
|Derivatives                                                                                                                                                                      |  |              | 55,945    |      |   |         
|Other                                                                                                                                                                            |  |              | 5,053     |      |   | 9,526    
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Other Assets                                                                                                                                                               |  |              | 86,202    |      |   | 37,810   
|                                                                                                                                                                                 |  |              |           |      |   |          
|TOTAL ASSETS                                                                                                                                                                     |  | $            | 2,124,973 |      | $ | 1,380,703
|                                                                                                                                                                                 |  |              |           |      |   |          
|LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                             |  |              |           |      |   |          
|Current Liabilities:                                                                                                                                                             |  |              |           |      |   |          
|Accounts Payable                                                                                                                                                                 |  | $            | 100,565   |      | $ | 30,263   
|Accrued Royalties                                                                                                                                                                |  |              | 20,301    |      |   | 12,896   
|Accrued Severance Taxes                                                                                                                                                          |  |              | 3,672     |      |   | 2,620    
|Related Parties                                                                                                                                                                  |  |              | 2,234     |      |   |         
|Short-Term Notes Payable                                                                                                                                                         |  |              | 72,700    |      |   |         
|Deferred Income Taxes                                                                                                                                                            |  |              | 55,000    |      |   | 1,269    
|Current Portion of Long-Term Debt                                                                                                                                                |  |              | 8,462     |      |   | 5,819    
|Other Current Liabilities                                                                                                                                                        |  |              | 18,116    |      |   | 9,817    
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Current Liabilities                                                                                                                                                        |  |              | 281,050   |      |   | 62,684   
|Long-Term Debt:                                                                                                                                                                  |  |              |           |      |   |          
|Long-Term Debt                                                                                                                                                                   |  |              | 15,386    |      |   | 5,799    
|Capital Lease Obligations                                                                                                                                                        |  |              | 59,296    |      |   | 61,150   
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Long-Term Debt                                                                                                                                                             |  |              | 74,682    |      |   | 66,949   
|Deferred Credits and Other Liabilities:                                                                                                                                          |  |              |           |      |   |          
|Derivatives                                                                                                                                                                      |  |              |          |      |   | 1,092    
|Deferred Income Taxes                                                                                                                                                            |  |              | 331,338   |      |   | 188,415  
|Asset Retirement Obligations                                                                                                                                                     |  |              | 7,401     |      |   | 3,981    
|Postretirement Benefits Other Than Pensions                                                                                                                                      |  |              | 2,728     |      |   | 2,700    
|Other                                                                                                                                                                            |  |              | 42,900    |      |   | 31,645   
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Deferred Credits and Other Liabilities                                                                                                                                     |  |              | 384,367   |      |   | 227,833  
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Liabilities                                                                                                                                                                |  |              | 740,099   |      |   | 357,466  
|                                                                                                                                                                                 |  |              |           |      |   |          
|Stockholders Equity:                                                                                                                                                            |  |              |           |      |   |          
|Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,971,636 Issued and Outstanding at December 31, 2008 and 150,915,198
Issued and Outstanding at December 31, 2007 |  |              | 1,510     |      |   | 1,509    
|Capital in Excess of Par Value                                                                                                                                                   |  |              | 789,625   |      |   | 785,575  
|Preferred Stock, 5,000,000 Shares Authorized; None Issued and Outstanding                                                                                                        |  |              |          |      |   |         
|Retained Earnings                                                                                                                                                                |  |              | 468,955   |      |   | 229,962  
|Other Comprehensive Income                                                                                                                                                       |  |              | 124,784   |      |   | 6,191    
|                                                                                                                                                                                 |  |              |           |      |   |          
|Total Stockholders Equity                                                                                                                                                       |  |              | 1,384,874 |      |   | 1,023,237
|                                                                                                                                                                                 |  |              |           |      |   |          
|TOTAL LIABILITIES AND STOCKHOLDERS EQUITY                                                                                                                                       |  | $            | 2,124,973 |      | $ | 1,380,703
|                                                                                                                                                                                 |  |              |           |      |   |          



The accompanying notes
are an integral part of these consolidated financial statements.



64



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##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Dollars in thousands except in per share data)



|                                                                          |  |             |       |                             |   |         |                           |  |   |                                            |   |  |                                              |         |   |                          |   |        |   |  |   |           |  
|------------------------------------------------------------------------- |  | ----------- | ----- | --------------------------- | - | ------- | ------------------------- |  | - | ------------------------------------------ | - |  | -------------------------------------------- | ------- | - | ------------------------ | - | ------ | - |  | - | --------- | -
|                                                                          |  | CommonStock |       | Capital InExcessof ParValue |   |         | RetainedEarnings(Deficit) |  |   | AccumulatedOtherComprehensiveIncome (Loss) |   |  | UnearnedCompensationon RestrictedStock Units |         |   | TotalStockholdersEquity |  
|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  |   |                          |   |       |   |  |   | 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   |   |                          |   |       |   |  |   | 880,215   |  
|Net Income                                                                |  |             |      |                             |   |        |                           |  |   | 135,678                                    |   |  |                                              |        |   |                          |   |       |   |  |   | 135,678   |  
|Gas Cash Flow Hedge (Net of $2,145 tax)                                   |  |             |      |                             |   |        |                           |  |   |                                           |   |  |                                              | 4,214   |   |                          |   |       |   |  |   | 4,214     |  
|FAS 158 Other Post Employment Benefits 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 Stock Based Compensation Awards                           |  |             |      |                             |   | 3,260   |                           |  |   |                                           |   |  |                                              |        |   |                          |   |       |   |  |   | 3,260     |  
|                                                                          |  |             |       |                             |   |         |                           |  |   |                                            |   |  |                                              |         |   |                          |   |        |   |  |   |           |  
|Balance at December 31, 2007                                              |  | $           | 1,509 |                             | $ | 785,575 |                           |  | $ | 229,962                                    |   |  | $                                            | 6,191   |   |                          | $ |       |   |  | $ | 1,023,237 |  
|Net Income                                                                |  |             |      |                             |   |        |                           |  |   | 239,073                                    |   |  |                                              |        |   |                          |   |       |   |  |   | 239,073   |  
|Gas Cash Flow Hedge (Net of ($77,291) tax)                                |  |             |      |                             |   |        |                           |  |   |                                           |   |  |                                              | 118,646 |   |                          |   |       |   |  |   | 118,646   |  
|Issuance of Common Stock                                                  |  |             | 1     |                             |   |        |                           |  |   |                                           |   |  |                                              |        |   |                          |   |       |   |  |   | 1         |  
|Amortization of Prior Service Costs and Actuarial Losses (Net of $52 tax) |  |             |      |                             |   |        |                           |  |   |                                           |   |  |                                              | (83     | ) |                          |   |       |   |  |   | (83       | )
|FAS 158 Other Post Employment Benefits Adjustment (Net of ($70) tax)      |  |             |      |                             |   |        |                           |  |   |                                           |   |  |                                              | 109     |   |                          |   |       |   |  |   | 109       |  
|FAS 158 Pension Adjustment (Net of ($38) tax)                             |  |             |      |                             |   |        |                           |  |   |                                           |   |  |                                              | (59     | ) |                          |   |       |   |  |   | (59       | )
|                                                                          |  |             |       |                             |   |         |                           |  |   |                                            |   |  |                                              |         |   |                          |   |        |   |  |   |           |  
|Comprehensive Income                                                      |  |             | 1     |                             |   |        |                           |  |   | 239,073                                    |   |  |                                              | 118,613 |   |                          |   |       |   |  |   | 357,687   |  
|Cumulative Effect of FAS 158 Measurement Adoption (Net of $64 tax)        |  |             |      |                             |   |        |                           |  |   | (80                                        | ) |  |                                              | (20     | ) |                          |   |       |   |  |   | (100      | )
|Stock Options Exercised                                                   |  |             |      |                             |   | 292     |                           |  |   |                                           |   |  |                                              |        |   |                          |   |       |   |  |   | 292       |  
|Tax Benefit from Stock-Based Compensation                                 |  |             |      |                             |   | 380     |                           |  |   |                                           |   |  |                                              |        |   |                          |   |       |   |  |   | 380       |  
|Amortization of Stock Based Compensation Awards                           |  |             |      |                             |   | 3,378   |                           |  |   |                                           |   |  |                                              |        |   |                          |   |       |   |  |   | 3,378     |  
|                                                                          |  |             |       |                             |   |         |                           |  |   |                                            |   |  |                                              |         |   |                          |   |        |   |  |   |           |  
|Balance at December 31, 2008                                              |  | $           | 1,510 |                             | $ | 789,625 |                           |  | $ | 468,955                                    |   |  | $                                            | 124,784 |   |                          | $ |       |   |  | $ | 1,384,874 |  
|                                                                          |  |             |       |                             |   |         |                           |  |   |                                            |   |  |                                              |         |   |                          |   |        |   |  |   |           |  



The accompanying notes
are an integral part of these consolidated financial statements.



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CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands, except per share data)



|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|--------------------------------------------------------------------------------- |  | -------------------------------- | -------- | - | ---- | - | -------- | ---- |  | - | -------- | -
|                                                                                  |  | For the Years Ended December 31, |         
|                                                                                  |  | 2008                             |          |   | 2007 |   |          | 2006 | 
|Operating Activities:                                                             |  |                                  |          |   |      |   |          |      |  |   |          |  
|Net Income                                                                        |  | $                                | 239,073  |   |      | $ | 135,678  |      |  | $ | 159,867  |  
|Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |  |                                  |          |   |      |   |          |      |  |   |          |  
|Depreciation, Depletion and Amortization                                          |  |                                  | 70,010   |   |      |   | 48,961   |      |  |   | 37,999   |  
|Stock-based Compensation                                                          |  |                                  | 3,378    |   |      |   | 3,260    |      |  |   | 3,733    |  
|Deferred Income Taxes                                                             |  |                                  | 117,870  |   |      |   | 70,352   |      |  |   | 60,358   |  
|Equity in Earnings of Affiliates                                                  |  |                                  | (551     | ) |      |   | (2,174   | )    |  |   | (978     | )
|Changes in Operating Assets:                                                      |  |                                  |         |   |      |   |         |      |  |   |         |  
|Accounts Receivable                                                               |  |                                  | (21,789  | ) |      |   | 8,267    |      |  |   | (6,682   | )
|Related Party Receivable                                                          |  |                                  | 3,256    |   |      |   | 1,723    |      |  |   | (2,017   | )
|Other Current Assets                                                              |  |                                  | 191      |   |      |   | 770      |      |  |   | (2,284   | )
|Changes in Other Assets                                                           |  |                                  | 3,861    |   |      |   | 2,294    |      |  |   | 83       |  
|Changes in Operating Liabilities:                                                 |  |                                  |          |   |      |   |          |      |  |   |          |  
|Accounts Payable                                                                  |  |                                  | 33,531   |   |      |   | 2,732    |      |  |   | (7,343   | )
|Income Taxes                                                                      |  |                                  | (28,515  | ) |      |   | (4,171   | )    |  |   | (3,327   | )
|Other Current Liabilities                                                         |  |                                  | 16,668   |   |      |   | 3,193    |      |  |   | 2,552    |  
|Changes in Other Liabilities                                                      |  |                                  | 10,611   |   |      |   | 1,968    |      |  |   | 1,668    |  
|Other                                                                             |  |                                  | (219     | ) |      |   | (405     | )    |  |   | (60      | )
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|Net Cash Provided by Operating Activities                                         |  |                                  | 447,375  |   |      |   | 272,448  |      |  |   | 243,569  |  
|Investing Activities:                                                             |  |                                  |          |   |      |   |          |      |  |   |          |  
|Capital Expenditures                                                              |  |                                  | (524,663 | ) |      |   | (295,422 | )    |  |   | (154,243 | )
|Acquisition of Knox Energy                                                        |  |                                  | (36,000  | ) |      |   |         |      |  |   |         |  
|Acquisition of Mineral Rights                                                     |  |                                  |         |   |      |   | (61,777  | )    |  |   |         |  
|Investment in Equity Affiliates                                                   |  |                                  | 1,081    |   |      |   | 2,785    |      |  |   | (1,777   | )
|Proceeds From Sales of Assets                                                     |  |                                  | 450      |   |      |   | 187      |      |  |   |         |  
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|Net Cash Used in Investing Activities                                             |  |                                  | (559,132 | ) |      |   | (354,227 | )    |  |   | (156,020 | )
|Financing Activities:                                                             |  |                                  |          |   |      |   |          |      |  |   |          |  
|Capital Lease Payments                                                            |  |                                  | (2,769   | ) |      |   | (2,552   | )    |  |   | (449     | )
|Proceeds from Variable Interest Equity Debt                                       |  |                                  | 11,032   |   |      |   | 8,851    |      |  |   |         |  
|Proceeds from Short-Term Borrowings                                               |  |                                  | 72,700   |   |      |   |         |      |  |   |         |  
|Exercise of Stock Options                                                         |  |                                  | 292      |   |      |   | 302      |      |  |   |         |  
|Tax Benefit from Stock Based Compensation                                         |  |                                  | 380      |   |      |   | 53       |      |  |   |         |  
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|Net Cash Provided by Financing Activities                                         |  |                                  | 81,635   |   |      |   | 6,654    |      |  |   | (449     | )
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|Net Decrease in Cash and Cash Equivalents                                         |  |                                  | (30,122  | ) |      |   | (75,125  | )    |  |   | 87,100   |  
|Cash and Cash Equivalents at Beginning of Period                                  |  |                                  | 32,048   |   |      |   | 107,173  |      |  |   | 20,073   |  
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  
|Cash and Cash Equivalents at End of Period                                        |  | $                                | 1,926    |   |      | $ | 32,048   |      |  | $ | 107,173  |  
|                                                                                  |  |                                  |          |   |      |   |          |      |  |   |          |  



The accompanying notes
are an integral part of these consolidated financial statements.

See Note 15Supplemental Cash Flow Information



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Note 1Significant Accounting Policies:



A summary of the significant accounting policies of CNX Gas is presented below. These, together with the other notes that follow, are an integral part of
the consolidated financial statements.



Basis of
Consolidation



The consolidated financial statements
of CNX Gas include the accounts of majority-owned and controlled subsidiaries. Investments in business entities in which CNX Gas does not have control, but has the ability to exercise significant influence over the operating and financial policies,
are accounted for under the equity method. All significant intercompany transactions and accounts have been eliminated in consolidation.



CNX Gas uses the equity method of accounting for our 50% ownership in Buchanan Generation for the years presented. The company also used the equity method
of accounting for our 50% ownership in Knox Energy and Coalfield Pipeline Company for the year ended December 31, 2007 and 2006. The remaining interest which CNX Gas did not previously own in Knox Energy, LLC and Coalfield Pipeline Company was
purchased in 2008 and these entities are now fully consolidated.



Use of Estimates



The preparation of
financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses,
and various disclosures. Actual results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to derivative instruments, contingencies, net recoverable reserves, asset
retirement obligations, income taxes, and stock based compensation.



Cash and Cash Equivalents



Cash and
cash equivalents include cash on hand and in financial institutions as well as all highly liquid short-term securities with original maturities of three months or less.



Trade Accounts Receivable



Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CNX Gas reserves for specific accounts receivable when it is
probable that all or a part of an outstanding balance will not be collected. CNX Gas regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off
against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Reserves for uncollectible amounts were not material in the periods presented.



Property, Plant and Equipment



CNX Gas follows the successful efforts method of accounting for gas
properties. Accordingly, costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are
determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. Planned maintenance costs which do not extend the useful lives of existing
plant and equipment are expensed as incurred.



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Upon the sale or retirement of a complete or partial unit of proved property, the cost and related
accumulated depletion are eliminated from the property accounts, and the resultant gain or loss is recognized in other income.



CNX Gas computes depreciation on gathering assets using the straight-line method over their estimated economic lives, which range from 30-40 years. CNX
Gas amortizes acquisition costs on proved gas properties and mineral interests using the ratio of current production to the estimated aggregate proved gas reserves. Wells and related equipment and intangible drilling costs are amortized on a units
of production method using the ratio of current production to the estimated aggregate proved developed gas reserves. Units-of-production amortization rates are revised when events and circumstances indicate an adjustment is necessary, or at least
once a year, and accounted for prospectively.



Costs for
purchased and internally developed software are expensed until it has been determined that the software will result in probable future economic benefits and management has committed to funding the project. Thereafter, all direct costs of materials
and services incurred in developing or obtaining software, including certain payroll and benefit costs of employees associated with the project, are capitalized and amortized using the straight-line method over the estimated useful life which does
not exceed 7 years.



Impairment of Long-Lived Assets



Impairment of long-lived assets is recorded when
indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets carrying value. The carrying value of the assets is then reduced to their estimated fair value which is
usually measured based on an estimate of future discounted cash flows. Impairment of equity investments is recorded when indicators of impairment are present and the estimated fair value of the investment is less than the assets carrying
value. There were no impairment losses during the periods presented in the Consolidated Financial Statements.



Income Taxes



CNX Gas is included in the consolidated federal income tax return of CONSOL Energy. Separate company state tax returns are filed in those states in which
CNX Gas is registered to do business. Income taxes are calculated as if CNX Gas files a tax return on a separate company basis. Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been
recognized in CNX Gas financial statements or separate tax return that would be filed on a separate company basis. Deferred taxes result from differences between the financial and tax bases of CNX Gas assets and liabilities and are
adjusted for changes in tax rates and tax laws when changes are enacted. Valuation allowances are recorded to reduce deferred tax assets where it is more likely than not that a deferred tax benefit will not be realized.



In July 2006, the Financial Accounting Standards Board (FASB) released FASB
Interpretation No. 48, Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement 109 (FIN 48). FIN 48 provides a model for how a company should recognize, measure, present and disclose in its financial
statements uncertain tax positions that it has taken or expects to take on a tax return. FIN 48 was effective for CNX Gas on January 1, 2007. The adoption of FIN 48 did not have a material impact on CNX Gas consolidated financial
statements.



Asset Retirement Obligations



CNX Gas accrues for dismantling and removing costs of
gas related facilities using the accounting treatment prescribed by Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Obligations (SFAS No. 143). This statement requires 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 present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is
generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Accretion expense is
included in lifting costs on the Consolidated Statements of Income. Asset retirement obligations primarily relate to the plugging of gas wells upon exhaustion of the gas reserves.



Accrued costs of dismantling and removing gas related facilities are regularly reviewed by management and are revised for
changes in future estimated costs and regulatory requirements.



Revenue Recognition



Sales are
recognized when title passes to the customers. This occurs at the contractual point of delivery.



We have an operational gas balancing agreement with Columbia pipeline. The imbalance agreement is managed internally using the sales method of accounting.
The sales method recognizes revenue when the gas is taken by the purchaser.



Included in royalty interest gas sales are the revenues related to the portion of production associated with royalty interest owners.



CNX Gas sells gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and
re-sold on the same day at market price less a small transaction fee. These matching buy/sell transactions include a legal right of offset of obligations and have been simultaneously entered into with the counterparty which qualify for netting under
EITF No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counter-Party and are therefore reflected net on the income statement in gathering and compression costs.



CNX Gas also provides gathering services to third parties by purchasing gas
produced by the third party, at market prices less a fee. The gas purchased from third party producers is then resold by CNX Gas to end users or gas marketers at current market prices. These revenues and expenses are recorded gross as purchased gas
revenue and purchased gas expense in the consolidated statement of income. Purchased gas revenue is recognized when title passes to the customer. Purchased gas expense is recognized when title passes to CNX Gas from the third party producer.



Royalty Recognition



Royalty costs for gas rights are included in royalty interest gas costs when
the related revenue for the gas sale is recognized. These royalty costs are paid in cash in accordance with the terms of each agreement. Revenues for gas sold related to production under royalty contracts, versus owned by CNX Gas, are separately
identified and recorded on a gross basis. The recognized revenues for these transactions are not net of related royalty fees.



Contingencies



CNX Gas and our subsidiaries from time to time are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death,
damage to property, exposure to hazardous substances,



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions, arising out of the normal
course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based
upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties. Legal fees associated with defending these
various lawsuits and claims are expensed when incurred.



Derivative Instruments



CNX Gas
accounts for derivative instruments in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS No. 133) and its corresponding amendments under
SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities an amendment of FASB Statement No. 133 (SFAS No. 138). CNX Gas measures every derivative instrument (including certain derivative
instruments embedded in other contracts) at fair value and records 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 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 only engages in cash flow hedges.



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.



Stock-Based Compensation



Effective January 1, 2006, CNX Gas adopted the fair value recognition
provisions of Statement of Financial Accounting Standards No. 123(R), Share-Based Payment (SFAS 123R), using the modified prospective transition method. Under this transition method, stock-based compensation expense for the years
presented include 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. CNX Gas recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. See Note 13 to the Consolidated Financial Statements
for a further discussion on stock-based compensation.



Earnings Per Share



Basic earnings per
share are computed by dividing net income by the weighted average shares outstanding during the years ended December 31, 2008, 2007 and 2006. Diluted earnings per share are calculated using the treasury stock method, which assumes outstanding
stock options were exercised and restricted stock units were converted into shares and the proceeds from such activity were used to acquire shares of common stock at the average market price during the reporting period. The dilutive effect is
calculated in a manner similar to the



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



calculation of basic earnings per share, except that the weighted average shares outstanding are increased to include additional shares from the assumed
exercise of stock options, if dilutive, and the assumed redemption of restricted stock units. Options to purchase 17,175 shares, 490,056 shares and 479,065 shares of common stock outstanding for the years ending December 31, 2008, 2007 and
2006, respectively, were not included in the computation of diluted earnings per share because the effect would be anti-dilutive.



|                                                      |  |                                |             |      |   |             |  |   |            
|----------------------------------------------------- |  | ------------------------------ | ----------- | ---- | - | ----------- |  | - | -----------
|                                                      |  | For the YearEnded December 31,
|                                                      |  | 2008                           |             | 2007 |   | 2006       
|Net Income                                            |  | $                              | 239,073     |      | $ | 135,678     |  | $ | 159,867    
|                                                      |  |                                |             |      |   |             |  |   |            
|Weighted Average Number of Common Shares Outstanding: |  |                                |             |      |   |             |  |   |            
|Basic                                                 |  |                                | 150,947,516 |      |   | 150,886,433 |  |   | 150,845,518
|Effect of stock-based compensation awards             |  |                                | 384,437     |      |   | 247,087     |  |   | 171,938    
|                                                      |  |                                |             |      |   |             |  |   |            
|Dilutive                                              |  |                                | 151,331,953 |      |   | 151,133,520 |  |   | 151,017,456
|                                                      |  |                                |             |      |   |             |  |   |            
|Earnings per share:                                   |  |                                |             |      |   |             |  |   |            
|Basic                                                 |  | $                              | 1.58        |      | $ | 0.90        |  | $ | 1.06       
|                                                      |  |                                |             |      |   |             |  |   |            
|Diluted                                               |  | $                              | 1.58        |      | $ | 0.90        |  | $ | 1.06       
|                                                      |  |                                |             |      |   |             |  |   |            



Shares of common stock
were outstanding as follows:



|                                             |  |             |  |             |  |            
|-------------------------------------------- |  | ----------- |  | ----------- |  | -----------
|                                             |  | 2008        |  | 2007        |  | 2006       
|Balance, beginning of year                   |  | 150,915,198 |  | 150,864,075 |  | 150,833,334
|Issuance related to stock-based compensation |  | 56,438      |  | 51,123      |  | 30,741     
|                                             |  |             |  |             |  |            
|Balance, end of year                         |  | 150,971,636 |  | 150,915,198 |  | 150,864,075
|                                             |  |             |  |             |  |            



Accounting for
Carbon Emission Offsets



In 2008, CNX Gas completed
the independent verification and registration processes necessary to sell carbon emission offsets on the Chicago Climate Exchange. CNX Gas has verified approximately 8.4 million metric tons of offsets. These offsets are recorded at their
historical cost, which is zero. Sales of these emission offsets will be reflected in other income as they occur. To date, no offsets have been sold.



Accounting for Business Combinations



The Company accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of SFAS no. 141,
Business Combinations. The total cost of acquisitions is allocated to the underlying identifiable net assets, based on their respective estimated fair values. Determining the fair value of assets acquired and liabilities assumed requires
managements judgment, and the utilization of independent valuation experts, and often involves the use of significant estimates and assumptions with respect to future cash inflows and outflows, discount rates, asset lives, and market
multiples, among other items.



Recent Accounting
Pronouncements



In May 2008, The Financial Accounting
Standards Board (FASB) issued Statement No. 162, The Hierarchy of Generally Accepted Accounting Principles. The new standard is intended to improve financial reporting by identifying a consistent framework, or hierarchy, for
selecting accounting principles to be used in



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preparing financial statements that are presented in conformity with U.S. generally accepted accounting principles (GAAP) for nongovernmental entities.
Statement 162 establishes that the GAAP hierarchy should be directed to entities because it is the entity (not its auditor) that is responsible for selecting accounting principles for financial statements that are presented in conformity with GAAP.
Statement 162 is effective 60 days following the SECs approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting
Principles. We do not expect this guidance to have a significant impact on CNX Gas.



In March 2008, The Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 161, disclosures about Derivative Instruments and Hedging Activities, an amendment of
FASB Statement 133 (SFAS 161). The new standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an
entitys financial positions, results of operations and cash flows. The new standard also improves transparency about how and why a company uses derivative instruments and how derivative instruments and related hedge items are accounted for
under Statement 133. It is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. CNX Gas management is currently assessing the new disclosure
requirements required by SFAS 161.



In December 2007, the
Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 141(R), 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.



Reclassifications



Certain amounts in prior periods have been reclassified to conform with the
report classifications of the year ended December 31, 2008 with no effect on previously reported net income or stockholders equity. These reclassifications include amounts related to other income and other expenses.



Note 2Significant Acquisitions:



In July 2008, CNX Gas completed the acquisition of several leases and gas
wells from KIS Oil & Gas Inc. for a cash payment of $19,324. The purchase price was principally allocated to property, plant, and equipment. The sales agreement called for the transfer of approximately 5,600 leased acres and 30 oil and
gas wells. This acquisition enhanced our acreage position in Northern Appalachia. The pro forma results for this acquisition were not significant to CNX Gas financial results.



In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline not
already owned by CNX Gas for a cash payment of $36,000 which was principally



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allocated to property, plant, and equipment. Prior to December 31, 2007 these companies were reported under the equity method. From December 31,
2007 to acquisition date, the companies were proportionately consolidated into CNX Gas financial statements. Knox Energy, LLC is a natural gas production company and Coalfield Pipeline is a natural gas transportation company with operations in
Tennessee. The pro forma results for this acquisition were not significant to CNX Gas financial results.



In June 2007, CNX Gas entered into a three-way transaction with Peabody Energy and majority shareholder CONSOL Energy Inc. (CONSOL or CONSOL Energy) to
acquire certain oil and gas, coalbed methane, and other gas interests. Pursuant to the transaction, CNX Gas acquired certain coal assets from CONSOL for $45,000 cash, plus $1,777 of miscellaneous acquisition costs, plus a future payment with an
estimated present value of $7,023, which we approximate to be the fair value of the assets. CNX Gas then exchanged those assets plus $15,000 cash for Peabodys oil and gas, coalbed methane, and other gas rights to approximately 985,000 acres,
including 603,000 acres in the Illinois Basin, 2,000 acres in Central Appalachia, 151,000 acres in Northern Appalachia, 171,000 acres in the San Juan Basin, 47,000 acres in the Powder River Basin, and 11,000 acres in the Rockies. This acreage has no
proved gas reserves.



Note 3Transactions with Related Parties:



CNX Gas sells gas to CONSOL Energy on a basis reflecting the
monthly average price received by CNX Gas from third party sales. CNX Gas revenue from CONSOL Energy was $7,337, $6,242 and $1,171 for the years ended December 31, 2008, 2007 and 2006, respectively. CNX Gas also sells gas to Buchanan
Generation, LLC, in which CNX Gas has a 50% interest, on both a market and discounted basis, depending on the circumstances. CNX Gas revenue from Buchanan Generation, LLC was $2,195, $5,376 and $7,319 for the years ended December 31, 2008, 2007
and 2006, respectively.



CNX Gas also purchases various
supplies from CONSOL Energys wholly owned subsidiary, Fairmont Supply. The cost of these items reflect current market prices and are included in lifting costs and gathering and compression costs as arms-length transactions. CNX Gas paid
Fairmont Supply $2,434, $699, and $210 for the years ended December 31, 2008, 2007, and 2006, respectively.



CNX Gas utilizes certain services and engages in operating transactions in the normal course of business with CONSOL Energy. The following represents a
summary of the significant transactions of this nature:



General and administrative expenses contain fees of $3,213, $1,635, and $3,954 for the years ended December 31, 2008, 2007, and 2006, respectively, for certain accounting and administrative services provided by CONSOL Energy. These
fees are allocated to CNX Gas based on annual estimated hours worked on CNX Gas versus total hours available.



CNX Gas also paid $150, $200, and $200 of rent for the years ended December 31, 2008, 2007, and 2006, respectively, for one of our facilities.



CNX Gas paid CONSOL Energy $61,397, $18,676 and $35,646 for
federal and state income taxes for years ended December 31, 2008, 2007 and 2006, respectively.



CONSOL Energy currently incurs drilling costs related to gob gas production due to the necessity to de-gas coal mines prior to production for safety
reasons. The cost to CONSOL Energy for drilling these wells was as follows: $14,073 in 2008, $7,101 in 2007, and $8,917 in 2006. CNX Gas captures and markets the gas from these wells and, therefore, benefits from this drilling activity, although CNX
Gas is not burdened with the cost to drill



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(Dollars in thousands, except per share data)



gob wells. CNX Gas is responsible for the costs incurred to gather and deliver the gob gas to market. All gob well drilling costs are borne by CONSOL Energy
and only the collection and processing costs are recorded in CNX Gas financial statements.



Employees may also participate in a defined contribution investment plan administered by CONSOL Energy. CONSOL Energy charges CNX Gas the actual amounts
contributed by CONSOL Energy on behalf of CNX Gas employees. Amounts charged to expense by CNX Gas for the investment plan were $1,757, $1,233, and $646 for the years ended December 31, 2008, 2007, and 2006, respectively. For all years
noted, this expense includes a matching contribution of up to 6% of an individuals eligible pay contributed to the plan. For the year ended December 31, 2008, the charge to expense also includes an additional 3% company contribution for
those employees hired on or after January 1, 2006, as well as those employees hired prior to December 31, 2005 who elected to freeze their defined benefit accruals as of January 1, 2007. Please see Note 12 to the Consolidated
Financial Statements for further information.



Eligible
employees may also participate in a long-term disability plan administered by CONSOL Energy. Benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled. CNX Gas
allocation of the long-term disability plan expense under this plan was $577, $493, and $321 for the years ended December 31, 2008, 2007, and 2006, respectively. Allocation of the expense for this plan is based on the percentage of CNX
Gas active salary employees compared to the total active salary employees covered by the plan.



CNX Gas also participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least
twenty years of service and have attained age 55 or fifteen years of service and have attained age 62. Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health
benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of one thousand dollars per year of service at retirement. Also,
the plan includes a cost sharing structure where essentially all participants contribute a minimum of 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants. CNX Gas does not expect to contribute to the
other postretirement benefit plan in 2009 and instead expects to pay benefit claims as they become due.



CNX Gas is insured through CONSOL Energy for workers compensation claims in several states and is self-insured for these claims in Virginia.
Workers compensation expense for these benefits was $32, $21, and $16 for the years ended December 31, 2008, 2007, and 2006, respectively.



CONSOL Energy has provided financial guarantees on behalf of CNX Gas. As discussed in Note 19 to the Consolidated Financial Statements, CNX Gas
anticipates that these parental guarantees will be transferred from CONSOL Energy to CNX Gas over time. We also believe that these parental guarantees will expire without being funded, and therefore will not have a material adverse effect on the
financial statements.



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(Dollars in thousands, except per share data)



Note 4Other Income:



|                                |  |                                 |        |      |   |       |  |   |        |  
|------------------------------- |  | ------------------------------- | ------ | ---- | - | ----- |  | - | ------ | -
|                                |  | For the YearsEnded December 31, |       
|                                |  | 2008                            |        | 2007 |   | 2006  | 
|Business Interruption Insurance |  | $                               | 8,000  |      | $ | 1,600 |  | $ | 10,165 |  
|Third Party Gathering Revenue   |  |                                 | 1,601  |      |   | 1,077 |  |   | 1,341  |  
|Timber Income                   |  |                                 | 768    |      |   | 99    |  |   |       |  
|Legal Settlement                |  |                                 | 650    |      |   |      |  |   |       |  
|Equity in Earnings              |  |                                 | 551    |      |   | 2,174 |  |   | (978   | )
|Interest Income                 |  |                                 | 400    |      |   | 3,793 |  |   | 3,453  |  
|Royalty Income                  |  |                                 |       |      |   |      |  |   | 10,230 |  
|Miscellaneous                   |  |                                 | 1,360  |      |   | 72    |  |   | 97     |  
|                                |  |                                 |        |      |   |       |  |   |        |  
|Total Other Income              |  | $                               | 13,330 |      | $ | 8,815 |  | $ | 24,308 |  
|                                |  |                                 |        |      |   |       |  |   |        |  



Note 5Income Taxes:



The following is a reconciliation, stated as a percentage
of pretax income, of the U.S. statutory federal income tax rate to CNX Gas effective tax rate:



|                                       |  |                                |         |   |      |      |    |         |   |        |      |  |      |         |  |   |        |   |  |      |   
|-------------------------------------- |  | ------------------------------ | ------- | - | ---- | ---- | -- | ------- | - | ------ | ---- |  | ---- | ------- |  | - | ------ | - |  | ---- | --
|                                       |  | For the YearEnded December 31, |        
|                                       |  | 2008                           |         |   | 2007 |      |    | 2006    |  
|                                       |  | Dollars                        |         |   | Rate |      |    | Dollars |   |        | Rate |  |      | Dollars |  |   | Rate   |  
|Statutory U.S. Federal Income Tax Rate |  | $                              | 137,455 |   |      | 35.0 | %  |         | $ | 77,223 |      |  | 35.0 | %       |  | $ | 89,754 |   |  | 35.0 | % 
|Net Effect of State Income Tax         |  |                                | 16,945  |   |      | 4.3  | %  |         |   | 9,108  |      |  | 4.1  | %       |  |   | 9,032  |   |  | 3.5  | % 
|Other                                  |  |                                | (744    | ) |      | (0.2 | )% |         |   | (1,370 | )    |  | (0.6 | )%      |  |   | (2,213 | ) |  | (0.8 | )%
|                                       |  |                                |         |   |      |      |    |         |   |        |      |  |      |         |  |   |        |   |  |      |   
|Income Tax Expense/Effective Rate      |  | $                              | 153,656 |   |      | 39.1 | %  |         | $ | 84,961 |      |  | 38.5 | %       |  | $ | 96,573 |   |  | 37.7 | % 
|                                       |  |                                |         |   |      |      |    |         |   |        |      |  |      |         |  |   |        |   |  |      |   



CNX Gas is included in
the consolidated federal income tax return of CONSOL Energy. Income taxes are calculated as if CNX Gas files a tax return on a separate company basis. CNX Gas is no longer subject to U.S. federal, state, and local, or non-U.S. income tax
examinations by tax authorities for tax years prior to 2003. The Internal Revenue Service (IRS) commenced an examination of CONSOL Energys U.S. income tax returns for 2004 and 2005. This examination is anticipated to be completed by
March 31, 2009. As of December 31, 2008, the IRS has not proposed any significant adjustments relating to any tax position taken by CNX Gas as part of CONSOL Energys consolidated federal income tax return.



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Income taxes provided on earnings consisted of:



|                         |  |                                |         |      |   |        |  |   |       
|------------------------ |  | ------------------------------ | ------- | ---- | - | ------ |  | - | ------
|                         |  | For the YearEnded December 31,
|                         |  | 2008                           |         | 2007 |   | 2006  
|Current:                 |  |                                |         |      |   |        |  |   |       
|Federal                  |  | $                              | 29,622  |      | $ | 13,836 |  | $ | 30,032
|State                    |  |                                | 6,164   |      |   | 2,755  |  |   | 6,183 
|                         |  |                                |         |      |   |        |  |   |       
|                         |  |                                | 35,786  |      |   | 16,591 |  |   | 36,215
|Deferred:                |  |                                |         |      |   |        |  |   |       
|Federal                  |  |                                | 98,144  |      |   | 57,112 |  |   | 52,646
|State                    |  |                                | 19,726  |      |   | 11,258 |  |   | 7,712 
|                         |  |                                |         |      |   |        |  |   |       
|                         |  |                                | 117,870 |      |   | 68,370 |  |   | 60,358
|                         |  |                                |         |      |   |        |  |   |       
|Total Income Tax Expense |  | $                              | 153,656 |      | $ | 84,961 |  | $ | 96,573
|                         |  |                                |         |      |   |        |  |   |       



The components of the
net deferred tax liabilities are as follows:



|                                |  |                    |          |   |      |   |          |  
|------------------------------- |  | ------------------ | -------- | - | ---- | - | -------- | -
|                                |  | As of December 31, |         
|                                |  | 2008               |          |   | 2007 |  
|Deferred Tax Assets:            |  |                    |          |   |      |   |          |  
|Capital Lease Obligations       |  | $                  | 23,924   |   |      | $ | 25,043   |  
|Derivatives                     |  |                    |         |   |      |   | 428      |  
|Asset Retirement Obligations    |  |                    | 2,904    |   |      |   | 1,560    |  
|Other Postretirement Benefits   |  |                    | 1,154    |   |      |   | 1,058    |  
|Stock-Based Compensation        |  |                    | 1,868    |   |      |   | 1,176    |  
|Other                           |  |                    | 7,844    |   |      |   | 9,724    |  
|                                |  |                    |          |   |      |   |          |  
|Total Deferred Tax Assets       |  |                    | 37,694   |   |      |   | 38,989   |  
|                                |  |                    |          |   |      |   |          |  
|Deferred Tax Liabilities:       |  |                    |          |   |      |   |          |  
|Property, Plant and Equipment   |  |                    | (338,435 | ) |      |   | (216,554 | )
|Investment in Equity Affiliates |  |                    | (4,536   | ) |      |   | (6,936   | )
|Derivatives                     |  |                    | (81,061  | ) |      |   | (4,197   | )
|Other                           |  |                    |         |   |      |   | (986     | )
|                                |  |                    |          |   |      |   |          |  
|Total Deferred Tax Liabilities  |  |                    | (424,032 | ) |      |   | (228,673 | )
|                                |  |                    |          |   |      |   |          |  
|Net Deferred Tax Liabilities    |  | $                  | (386,338 | ) |      | $ | (189,684 | )
|                                |  |                    |          |   |      |   |          |  



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(Dollars in thousands, except per share data)



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. During the years ending December 31, 2008 and December 31, 2007, the Company recognized an increase in the liability relating to unrecognized tax benefits of $1,012 and
$1,417, respectively. The balance of unrecognized tax benefits as of December 31, 2008 and 2007 was $5,545 and $4,533, respectively. The unrecognized tax changes include tax positions for which the ultimate deductibility is certain, but for
which there is uncertainty about the proper tax year in which the tax positions are deductible. Consequently, these unrecognized tax benefits during 2008 and 2007 would not have an impact on CNX Gas effective income tax rate. A reconciliation
of the beginning and ending unrecognized tax benefits is as follows:



|                                                |  |   |      
|----------------------------------------------- |  | - | -----
|Balance at December 31, 2007                    |  | $ | 4,533
|Additions related to current year tax positions |  |   | 1,012
|                                                |  |   |      
|Balance at December 31, 2008                    |  | $ | 5,545
|                                                |  |   |      



CNX Gas recognizes
interest accrued related to unrecognized tax benefits in its interest expense. As of December 31, 2008 and December 31, 2007, CNX Gas reported an accrued interest liability relating to uncertain tax positions of $516 and $182 respectively.
The accrued interest liability for these periods includes $334 and $90 of interest expense that is reflected in the Companys statements of operations for the years ended December 31, 2008 and 2007 respectively.



CNX Gas recognizes penalties accrued related to unrecognized tax benefits in
its income tax expense. As of December 31, 2008 and 2007, the Company had no accrued penalties relating to its uncertain income tax positions.



All of CNX Gas earnings before income tax was generated from domestic entities.



Note 6Asset Retirement Obligations:



CNX Gas accrues for asset retirement obligations using the accounting treatment prescribed by Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations (SFAS No. 143). CNX Gas recognizes capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation.



The reconciliation of changes in the asset retirement
obligations at December 31, 2008 and 2007 is as follows:



|                                  |  |                    |       |      |   |        |  
|--------------------------------- |  | ------------------ | ----- | ---- | - | ------ | -
|                                  |  | As of December 31, |      
|                                  |  | 2008               |       | 2007 |  
|Balance at beginning of period    |  | $                  | 3,981 |      | $ | 9,214  |  
|Accretion expense                 |  |                    | 460   |      |   | 267    |  
|Payments                          |  |                    |      |      |   | (144   | )
|Liabilities incurred              |  |                    | 1,943 |      |   | 1,180  |  
|Revisions in estimated cash flows |  |                    | 1,017 |      |   | (6,536 | )
|                                  |  |                    |       |      |   |        |  
|Balance at end of period          |  | $                  | 7,401 |      | $ | 3,981  |  
|                                  |  |                    |       |      |   |        |  



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(Dollars in thousands, except per share data)



For the year ended December 31, 2008, the revisions in estimated cash flows are due primarily to
the effect on the present value of an increase in the estimated average plugging costs of our wells. For the year ended December 31, 2007, the revisions in estimated cash flows are due primarily to the effect on the present value of an increase
in the estimated average life of our wells.



Note 7Property, Plant and
Equipment:



|                                                     |  |                    |           |   |      |   |           |  
|---------------------------------------------------- |  | ------------------ | --------- | - | ---- | - | --------- | -
|                                                     |  | As of December 31, |          
|                                                     |  | 2008               |           |   | 2007 |  
|Leasehold Improvements                               |  | $                  | 1,352     |   |      | $ | 1,351     |  
|Proved Properties                                    |  |                    | 121,605   |   |      |   | 104,515   |  
|Unproved Properties                                  |  |                    | 220,848   |   |      |   | 101,680   |  
|Wells and Related Equipment                          |  |                    | 222,685   |   |      |   | 166,468   |  
|Intangible Drilling                                  |  |                    | 793,456   |   |      |   | 531,097   |  
|Gathering Assets                                     |  |                    | 740,396   |   |      |   | 596,173   |  
|Asset Retirement Obligations                         |  |                    | 3,739     |   |      |   | 1,035     |  
|Capitalized Internal Software                        |  |                    | 7,302     |   |      |   | 6,741     |  
|                                                     |  |                    |           |   |      |   |           |  
|Total Property, Plant and Equipment                  |  |                    | 2,111,383 |   |      |   | 1,509,060 |  
|Accumulated Depreciation, Depletion and Amortization |  |                    | (322,470  | ) |      |   | (254,154  | )
|                                                     |  |                    |           |   |      |   |           |  
|Property and Equipment, net                          |  | $                  | 1,788,913 |   |      | $ | 1,254,906 |  
|                                                     |  |                    |           |   |      |   |           |  



Property, plant and
equipment includes gross assets acquired under capital leases of $69,990 and $66,919 at December 31, 2008 and 2007, respectively. Related amounts in accumulated depreciation, depletion and amortization are $10,900 and $5,242 at
December 31, 2008 and 2007, respectively.



Note 8Credit
Facility:



CNX Gas has a five-year $200,000 unsecured
credit agreement which extends through October 2010. The agreement gives CNX Gas the ability to request an increase in the aggregate outstanding principal amount up to $300,000, including borrowings and letters of credit. The $200,000 credit
agreement for CNX Gas is unsecured; however, it does contain a negative pledge provision providing that CNX Gas assets cannot be used to secure any other obligations. Fees and interest rate spreads are based on the percentage of facility
utilization, measured quarterly. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CNX Gas stock and merge with another corporation. The facility includes a maximum leverage ratio covenant of not
more than 3.00 to 1.00, measured quarterly. The leverage ratio was 0.32 to 1.00 at December 31, 2008. The facility also includes a minimum interest coverage ratio of no less than 3.00 to 1.00, measured quarterly. The interest coverage ratio
covenant was 77.29 to 1.00 at December 31, 2008.



At
December 31, 2008, the CNX Gas credit agreement had outstanding borrowings of $72,700 and $14,933 of letters of credit outstanding, leaving $112,367 of capacity available for borrowings and the issuance of letters of credit. The outstanding
borrowings had a weighted average interest rate of 3.51% during the year ended December 31, 2008.



CNX Gas and subsidiaries have executed a Supplemental Indenture and are guarantors of CONSOL Energys 7.875% notes due March 1, 2012 in the
principal amount of $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture governing CONSOL Energys 7.875% notes would require CNX Gas to ratably secure the notes.



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(Dollars in thousands, except per share data)



Note 9Other Current Liabilities:



|                                       |  |                    |        |      |   |      
|-------------------------------------- |  | ------------------ | ------ | ---- | - | -----
|                                       |  | As of December 31,
|                                       |  | 2008               |        | 2007
|Short Term Incentive Compensation Plan |  | $                  | 8,108  |      | $ | 5,241
|Accrued Property Taxes                 |  |                    | 2,894  |      |   | 577  
|Accrued Payroll and Benefits           |  |                    | 2,416  |      |   | 455  
|Accrued Firm Transportation            |  |                    | 1,380  |      |   | 474  
|Purchased Gas                          |  |                    | 1,256  |      |   | 1,815
|Other                                  |  |                    | 2,062  |      |   | 1,255
|                                       |  |                    |        |      |   |      
|Total Other Current Liabilities        |  | $                  | 18,116 |      | $ | 9,817
|                                       |  |                    |        |      |   |      



Note 10Leases:



CNX Gas uses various leased facilities and equipment in
our operations. Future minimum lease payments under capital and operating leases, together with the present value of the net minimum capital lease payments, at December 31, 2008, are as follows:



|                                         |  |               |         |   |                 |   |       
|---------------------------------------- |  | ------------- | ------- | - | --------------- | - | ------
|                                         |  | CapitalLeases |         |   | OperatingLeases
|2009                                     |  | $             | 9,191   |   |                 | $ | 2,443 
|2010                                     |  |               | 8,185   |   |                 |   | 2,154 
|2011                                     |  |               | 7,949   |   |                 |   | 1,777 
|2012                                     |  |               | 7,548   |   |                 |   | 1,406 
|2013                                     |  |               | 7,380   |   |                 |   | 1,380 
|Thereafter                               |  |               | 57,754  |   |                 |   | 2,208 
|                                         |  |               |         |   |                 |   |       
|Total Minimum Lease Payments             |  |               | 98,007  |   |                 | $ | 11,368
|                                         |  |               |         |   |                 |   |       
|Less Imputed Interest                    |  |               | (34,746 | ) |                 |   |       
|                                         |  |               |         |   |                 |   |       
|Present Value of Minimum Lease Payments  |  |               | 63,261  |   |                 |   |       
|Less Amount Due in One Year              |  |               | 3,965   |   |                 |   |       
|                                         |  |               |         |   |                 |   |       
|Total Long-term Capital Lease Obligation |  | $             | 59,296  |   |                 |   |       
|                                         |  |               |         |   |                 |   |       



We are a party to a
15-year capital lease obligation through October 2021. Under this agreement, we are guaranteed approximately 197,500 mcf of capacity daily on the Jewell Ridge lateral pipeline. This lease does not transfer ownership at the end of the term.



Rental expense under operating leases was $9,381, $6,675, and
$4,650 for the years ended December 31, 2008, 2007, and 2006, respectively.



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Note 11Long-Term Debt:



|                                                                                                       |  |                       |       
|------------------------------------------------------------------------------------------------------ |  | --------------------- | ------
|                                                                                                       |  | As ofDecember 31,2008
|Debt:                                                                                                  |  |                       |       
|Note PayableHuntington National Bank, due 2011 at 6.10%                                               |  | $                     | 18,940
|Members loans payable, due various undetermined dates, no interest                                     |  |                       | 621   
|Other notes payable, due various dates through 2011 with interest rates ranging from 7.350% to 10.423% |  |                       | 322   
|                                                                                                       |  |                       |       
|Total Debt                                                                                             |  |                       | 19,883
|Less amounts due in one year                                                                           |  |                       | 4,497 
|                                                                                                       |  |                       |       
|Total Long-term Debt                                                                                   |  | $                     | 15,386
|                                                                                                       |  |                       |       



Maturities on
long-term debt in each of the next five years are as follows:



|                                |  |   |       
|------------------------------- |  | - | ------
|2009                            |  | $ | 4,497 
|2010                            |  |   | 4,674 
|2011                            |  |   | 10,091
|2012                            |  |   |      
|2013                            |  |   |      
|Thereafter                      |  |   | 621   
|                                |  |   |       
|Total Long-Term Debt Maturities |  | $ | 19,883
|                                |  |   |       



Note 12Pension and Other
Postretirement Benefits:



As of December 31, 2005,
CNX Gas participated in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The pension benefit obligation earned by salaried CNX Gas employees prior to the date of
separation from CONSOL Energy remains with CONSOL Energy. As of the date of separation, any incremental pension liability earned by CNX Gas salaried employees, as a result of service after August 1, 2005, is the obligation of CNX Gas. The
benefits for this plan are based primarily on years of service and employees compensation near retirement. On January 1, 2006, an amendment was made to the CONSOL Energy Inc. Employee Retirement Plan that suspended all service accruals of
gas employees in this plan. In its place, an identical plan, the CNX Gas Corporation Employee Retirement Plan (Pension Plan), was created and sponsored by CNX Gas to provide a benefit for all defined benefit accruals going forward. As of that date,
the lump sum benefits formula was frozen for service and salaries and prospectively the lump sum option will not be offered for any benefits earned after January 1, 2006. Also, the amount of future benefit accruals was reduced and early
retirement subsidies were eliminated.



Effective
January 1, 2007, employees hired by CNX Gas will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit plan, these employees will begin receiving
an additional 3% company contribution into their defined contribution plan. CNX Gas employees who were hired prior to December 31, 2005, or who were full time salaried employees of CONSOL Energy immediately prior to their date of transfer, were
given a one time opportunity to elect to remain in the defined benefit plan or to freeze their defined benefit accruals and participate in the additional 3% company contribution into their defined contribution plan. All employees, regardless of the
hire date or plan



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



election, will continue to receive up to a 6% company match of eligible pay contributed to the defined contribution plan. In addition, any employees hired on
or after January 1, 2006 had their pension benefit frozen as of December 31, 2006 and were automatically enrolled into the additional 3% company contribution into their defined contribution plan effective January 1, 2007. The Company
intends to freeze all defined benefit accruals after ten years for employees that elected to remain in the defined benefit plan.



CNX Gas adopted the measurement provisions of Statement of Financial Accounting Standards No. 158 Employers Accounting for Defined
Benefit Pension and Other Postretirement Plans (SFAS 158), during the year ended December 31, 2008. As a result of this adoption, the Company recognized an increase of $85 and $79 in the pension and other postretirement benefit
liabilities, respectively, which was accounted for as a reduction in the January 1, 2008 balance of retained earnings.



CNX Gas participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least
twenty years of service and have attained age 55 or fifteen years of service and have attained age 62. Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health
benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of $1,000 per year of service at retirement. The plan structure
includes a cost sharing arrangement where essentially all participants contribute 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants.



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(Dollars in thousands, except per share data)



The reconciliation of changes in the benefit obligation, plan assets and funded status of this plan
at December 31, 2008 and 2007 is as follows:



|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|------------------------------------------------------------------------ |  | -------------------------------- | ----- | - | ------------------------------ | - | ---- | ---- |  | - | ------ | - |  | - | ------ | -
|                                                                         |  | Pension Benefits at December 31, |       |   | Other Benefits at December 31, |  
|                                                                         |  | 2008                             |       |   | 2007                           |   |      | 2008 |  |   | 2007   |  
|Change in benefit obligation:                                            |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Benefit obligation at beginning of year                                  |  | $                                | 615   |   |                                | $ | 207  |      |  | $ | 2,814  |   |  | $ | 2,325  |  
|Service cost (9/30/07-12/31/07)                                          |  |                                  | 80    |   |                                |   |     |      |  |   | 33     |   |  |   |       |  
|Service cost                                                             |  |                                  | 323   |   |                                |   | 262  |      |  |   | 132    |   |  |   | 124    |  
|Interest cost (9/30/07-12/31/07)                                         |  |                                  | 10    |   |                                |   |     |      |  |   | 46     |   |  |   |       |  
|Interest cost                                                            |  |                                  | 40    |   |                                |   | 12   |      |  |   | 183    |   |  |   | 139    |  
|Actuarial loss (gain)                                                    |  |                                  | 110   |   |                                |   | 150  |      |  |   | (145   | ) |  |   | 335    |  
|Benefits paid (9/30/07-12/31/07)                                         |  |                                  | (5    | ) |                                |   |     |      |  |   | (34    | ) |  |   |       |  
|Benefits paid                                                            |  |                                  | (28   | ) |                                |   | (16  | )    |  |   | (147   | ) |  |   | (109   | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Benefit obligation at end of period                                      |  | $                                | 1,145 |   |                                | $ | 615  |      |  | $ | 2,882  |   |  | $ | 2,814  |  
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Change in plan assets:                                                   |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Fair value of plan assets at beginning of period                         |  | $                                | 288   |   |                                | $ | 18   |      |  | $ |       |   |  | $ |       |  
|Actual return on plan assets                                             |  |                                  |      |   |                                |   | (51  | )    |  |   |       |   |  |   |       |  
|Company contributions (9/30/07-12/31/07)                                 |  |                                  | 43    |   |                                |   |     |      |  |   | 33     |   |  |   |       |  
|Company contributions                                                    |  |                                  | 518   |   |                                |   | 337  |      |  |   | 147    |   |  |   | 109    |  
|Benefits and other payments (9/30/07-12/31/07)                           |  |                                  | (5    | ) |                                |   |     |      |  |   | (33    | ) |  |   |       |  
|Benefits paid                                                            |  |                                  | (28   | ) |                                |   | (16  | )    |  |   | (147   | ) |  |   | (109   | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Fair value of plan assets at end of period                               |  | $                                | 816   |   |                                | $ | 288  |      |  | $ |       |   |  | $ |       |  
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Funded status:                                                           |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Current liabilities                                                      |  | $                                |      |   |                                | $ |     |      |  | $ | (154   | ) |  | $ | (114   | )
|Noncurrent liabilities                                                   |  |                                  | (329  | ) |                                |   | (327 | )    |  |   | (2,728 | ) |  |   | (2,700 | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Net obligation recognized                                                |  | $                                | (329  | ) |                                | $ | (327 | )    |  | $ | (2,882 | ) |  | $ | (2,814 | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Amounts recognized in accumulated other comprehensive income consist of: |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Net actuarial (gain) loss                                                |  | $                                | 46    |   |                                | $ | (50  | )    |  | $ | 579    |   |  | $ | 803    |  
|Prior Service Credit                                                     |  |                                  |      |   |                                |   |     |      |  |   | (1,072 | ) |  |   | (1,287 | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  
|Net amount recognized (before tax effect)                                |  | $                                | 46    |   |                                | $ | (50  | )    |  | $ | (493   | ) |  | $ | (484   | )
|                                                                         |  |                                  |       |   |                                |   |      |      |  |   |        |   |  |   |        |  



The components of net
periodic benefit costs are as follows:



|                                            |  |                                  |     |   |                                  |   |     |      |  |   |      |   |  |      |      |   |      |   |      |   |  |   |      |  
|------------------------------------------- |  | -------------------------------- | --- | - | -------------------------------- | - | --- | ---- |  | - | ---- | - |  | ---- | ---- | - | ---- | - | ---- | - |  | - | ---- | -
|                                            |  | Pension Benefits                 |     |   | Other Benefits                   |  
|                                            |  | For the Years Ended December 31, |     |   | For the Years Ended December 31, |  
|                                            |  | 2008                             |     |   | 2007                             |   |     | 2006 |  |   | 2008 |   |  | 2007 |      |   | 2006 |  
|Components of net periodic benefit cost:    |  |                                  |     |   |                                  |   |     |      |  |   |      |   |  |      |      |   |      |   |      |   |  |   |      |  
|Service cost                                |  | $                                | 323 |   |                                  | $ | 262 |      |  | $ | 282  |   |  | $    | 132  |   |      | $ | 124  |   |  | $ | 91   |  
|Interest cost                               |  |                                  | 40  |   |                                  |   | 12  |      |  |   | 5    |   |  |      | 183  |   |      |   | 139  |   |  |   | 101  |  
|Expected return on plan assets              |  |                                  | (25 | ) |                                  |   | (2  | )    |  |   | (9   | ) |  |      |     |   |      |   |     |   |  |   |     |  
|Amortization of prior service cost (credit) |  |                                  |    |   |                                  |   |    |      |  |   |     |   |  |      | (172 | ) |      |   | (172 | ) |  |   | (172 | )
|Recognized net actuarial loss               |  |                                  |    |   |                                  |   | (23 | )    |  |   | (12  | ) |  |      | 36   |   |      |   | 21   |   |  |   |     |  
|                                            |  |                                  |     |   |                                  |   |     |      |  |   |      |   |  |      |      |   |      |   |      |   |  |   |      |  
|Benefit cost                                |  | $                                | 338 |   |                                  | $ | 249 |      |  | $ | 266  |   |  | $    | 179  |   |      | $ | 112  |   |  | $ | 20   |  
|                                            |  |                                  |     |   |                                  |   |     |      |  |   |      |   |  |      |      |   |      |   |      |   |  |   |      |  



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Amounts included in accumulated other comprehensive income, expected to be recognized in 2009 net
periodic benefit costs:



|                                         |  |                 |   |                        |   |    
|---------------------------------------- |  | --------------- | - | ---------------------- | - | ---
|                                         |  | PensionBenefits |   | PostretirementBenefits
|Prior service cost (benefit) recognition |  | $               |  |                        | $ | 172
|Actuarial loss recognition               |  | $               |  |                        | $ | 19 



The accumulated
benefit obligation for the Pension Plan at December 31, 2008 and 2007 was $894 and $470, respectively.



Assumptions:



The
weighted-average assumptions used to determine benefit obligations are as follows:



|                              |  |                                 |   |  |                               |   |  |      |   |  |      |  
|----------------------------- |  | ------------------------------- | - |  | ----------------------------- | - |  | ---- | - |  | ---- | -
|                              |  | Pension Benefits atDecember 31, |   |  | Other Benefits atDecember 31, |  
|                              |  | 2008                            |   |  | 2007                          |   |  | 2008 |   |  | 2007 |  
|Discount rate                 |  | 6.28                            | % |  | 6.57                          | % |  | 6.20 | % |  | 6.63 | %
|Rate of compensation increase |  | 5.34                            | % |  | 5.46                          | % |  |     |   |  |     |  



The weighted-average
assumptions used to determine net periodic benefit costs are as follows:



|                                         |  |                                 |   |  |                               |   |  |      |   |  |      |   |  |      |   |  |      |  
|---------------------------------------- |  | ------------------------------- | - |  | ----------------------------- | - |  | ---- | - |  | ---- | - |  | ---- | - |  | ---- | -
|                                         |  | Pension Benefits atDecember 31, |   |  | Other Benefits atDecember 31, |  
|                                         |  | 2008                            |   |  | 2007                          |   |  | 2006 |   |  | 2008 |   |  | 2007 |   |  | 2006 |  
|Discount rate                            |  | 6.57                            | % |  | 6.00                          | % |  | 5.75 | % |  | 6.63 | % |  | 6.00 | % |  | 5.75 | %
|Expected long-term return on plan assets |  | 8.00                            | % |  | 8.00                          | % |  | 8.00 | % |  |     |   |  |     |   |  |     |  
|Rate of compensation increase            |  | 5.46                            | % |  | 4.36                          | % |  | 4.11 | % |  |     |   |  |     |   |  |     |  



The long-term rate of
return is the sum of the portion of total assets in each asset class held multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets. The expected return for each class is determined using the plan
asset allocation at the measurement date and a distribution of compound average returns over a 20-year time horizon. The model uses asset class returns, variances and correlation assumptions to produce the expected return for each portfolio. The
return assumptions used forward-looking gross returns influenced by the current Treasury yield curve. These returns recognize current bond yields, corporate bond spreads and equity risk premiums based on current market conditions. In general, the
long-term rate of return is the sum of the portion of total assets in each asset class multiplied by the expected return for that class, adjusted for expected expenses to be paid from the assets.



The assumed health care cost trend rates are as follows:



|                                                                              |  |                    |   |  |      |   |  |      |  
|----------------------------------------------------------------------------- |  | ------------------ | - |  | ---- | - |  | ---- | -
|                                                                              |  | As of December 31, |  
|                                                                              |  | 2008               |   |  | 2007 |   |  | 2006 |  
|Healthcare cost trend rate for next year                                      |  | 9.60               | % |  | 8.00 | % |  | 8.50 | %
|Rate to which the cost trend rate is assumed to decline (ultimate trend rate) |  | 5.00               | % |  | 5.00 | % |  | 5.00 | %
|Year that the rate reaches ultimate trend rate                                |  | 2015               |   |  | 2013 |   |  | 2011 |  



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Assumed health care cost trend rates have a significant effect on the amounts reported for the
medical plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:



|                                                         |  |                            |     |                            |   |      |  
|-------------------------------------------------------- |  | -------------------------- | --- | -------------------------- | - | ---- | -
|                                                         |  | 1-PercentagePoint Increase |     | 1-PercentagePoint Decrease |  
|Effect on total of service and interest costs components |  | $                          | 47  |                            | $ | (39  | )
|Effect on accumulated postretirement benefit obligation  |  | $                          | 253 |                            | $ | (427 | )



Assumed discount rates
also have a significant effect on the amounts reported for both pension and other benefit costs. A one-quarter percentage point change in assumed discount rate would have the following effect on benefit costs:



|                                                        |  |                               |     |   |                               |   |   
|------------------------------------------------------- |  | ----------------------------- | --- | - | ----------------------------- | - | --
|                                                        |  | 0.25 PercentagePoint Increase |     |   | 0.25 PercentagePoint Decrease
|Pension benefit costs (decrease) increase               |  | $                             | (15 | ) |                               | $ | 17
|Other postemployment benefits costs (decrease) increase |  | $                             | (12 | ) |                               | $ | 13



Plan Assets:



As of December 31, 2008 and September 30, 2007, all of the pension
plan assets were held in cash and cash equivalents. CNX Gas had no plan assets as of December 31, 2008 and September 30, 2007 for other postretirement benefits.



Cash Flows:



We expect to contribute $400 to the Pension Plan in 2009. The Company does not expect to contribute to the other postretirement benefit plan in 2009. We
intend to pay benefit claims as they are due. The following benefit payments, reflecting future service, are expected to be paid as follows:



|               |  |                  |     |                |   |    
|-------------- |  | ---------------- | --- | -------------- | - | ---
|               |  | Pension Benefits |     | Other Benefits
|2009           |  | $                | 19  |                | $ | 154
|2010           |  |                  | 23  |                |   | 162
|2011           |  |                  | 29  |                |   | 170
|2012           |  |                  | 37  |                |   | 179
|2013           |  |                  | 48  |                |   | 145
|Year 2014-2018 |  |                  | 622 |                |   | 909



Note 13Stock-Based
Compensation:



CNX Gas adopted the amended CNX Gas Equity
Incentive Plan on October 11, 2006. The plan is administered by our board of directors and the board of directors may delegate administration of the plan to a committee of the board of directors. Our directors and employees, and our
affiliates (which include CONSOL Energy) directors and employees, are eligible to receive awards under the plan. Some of our employees including our executive officers and non-employee directors have participated in or have been eligible to
participate in and, will continue to be eligible to participate in, CNX Gas Equity Incentive Plan.



The CNX Gas Equity Incentive Plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance
awards, cash awards and other stock-based awards. The total number



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas plan is 2,500,000. When stock based awards are exercised or
vest, the issuances are made from CNX Gas unissued common shares.



The total stock-based compensation expense was $3,378, $3,260 and $3,733 for the years ended December 31, 2008, 2007 and 2006, respectively, and the related deferred tax benefit totaled $1,326, $1,277 and $1,455, respectively.



Effective January 1, 2006, CNX Gas adopted the fair value
recognition provisions of SFAS 123R, Share-Based Payment (SFAS 123R), using the modified prospective transition method. Under this transition method, stock-based compensation expense for all years presented includes compensation expense
for all stock-based compensation awards granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. Share-based compensation expense for all
share-based payment awards granted after January 1, 2006 is based on the grant date fair value in accordance with the provisions of FAS 123R. CNX Gas recognizes compensation costs net of an estimated forfeiture rate and recognizes the
compensation cost for only those shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term, or to an employees eligible retirement date, if earlier and
applicable.



As part of its SFAS 123R adoption, CNX Gas uses
the Black-Scholes option pricing model to value its options. The risk free interest rate was determined for each vesting tranche of an award based upon the calculated yield on U.S Treasury obligations for the expected term of the award. The expected
volatility and expected term of the awards were developed by examining the stock option activity for a peer group of companies. The expected forfeiture rate is estimated based upon historical forfeiture activity. The fair value of share based
payment awards was estimated using the Black-Scholes option pricing model with the following assumptions and weighted average fair values:



|                                      |  |                          |           |   |      |   |           |      |  |   |           |  
|------------------------------------- |  | ------------------------ | --------- | - | ---- | - | --------- | ---- |  | - | --------- | -
|                                      |  | Years Ended December 31, |          
|                                      |  | 2008                     |           |   | 2007 |   |           | 2006 | 
|Weighted Average Fair Value of Grants |  | $                        | 15.02     |   |      | $ | 9.61      |      |  | $ | 9.83      |  
|Risk Free Interest Rate               |  |                          | 4.58      | % |      |   | 4.58      | %    |  |   | 4.65      | %
|Expected Volatility                   |  |                          | 34.50     | % |      |   | 34.50     | %    |  |   | 32.39     | %
|Expected Forfeiture Rate              |  |                          | 2.0       | % |      |   | 2.0       | %    |  |   | 2.0       | %
|Expected Term                         |  |                          | 4.5 years |   |      |   | 4.5 years |      |  |   | 4.5 years |  



Stock Options
Awards



There are 972,307 employee stock options that
vest 25% per year, beginning one year after the grant date and 442,986 employee stock options that vest 100%, three years after the grant date. There are 24,989 non-employee director stock options outstanding which vest 33% per year,
beginning one year after the grant date. The vesting of the options will accelerate in the event of death, disability or retirement and may accelerate upon a change of control of CNX Gas. These stock options will terminate ten years after the date
on which they were granted. For the years ended December 31, 2008, 2007 and 2006, the total fair value of stock options granted was $30, $151 and $4,784, respectively.



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



A summary of the status of stock options granted is presented below:



|                                 |  |           |   |  |                               |       |                                                     |      |                                               |   |       
|-------------------------------- |  | --------- | - |  | ----------------------------- | ----- | --------------------------------------------------- | ---- | --------------------------------------------- | - | ------
|                                 |  | Shares    |   |  | WeightedAverageExercise Price |       | Weighted AverageRemainingContractual Term(in years) |      | AggregateIntrinsic Value(dollars inthousands)
|Balance at December 31, 2007     |  | 1,489,107 |   |  | $                             | 20.13 |                                                     | 7.85 |                                               |   |       
|Granted                          |  | 2,000     |   |  |                               | 41.50 |                                                     |      |                                               |   |       
|Exercised                        |  | (18,079   | ) |  |                               | 16.16 |                                                     |      |                                               |   |       
|Forfeited                        |  | (32,746   | ) |  |                               | 26.12 |                                                     |      |                                               |   |       
|                                 |  |           |   |  |                               |       |                                                     |      |                                               |   |       
|Balance at December 31, 2008     |  | 1,440,282 |   |  | $                             | 20.07 |                                                     | 6.85 |                                               | $ | 10,972
|                                 |  |           |   |  |                               |       |                                                     |      |                                               |   |       
|Vested and expected to vest      |  | 1,430,923 |   |  | $                             | 20.02 |                                                     | 6.84 |                                               | $ | 10,971
|                                 |  |           |   |  |                               |       |                                                     |      |                                               |   |       
|Exercisable at December 31, 2008 |  | 741,025   |   |  | $                             | 16.31 |                                                     | 6.61 |                                               | $ | 8,162 
|                                 |  |           |   |  |                               |       |                                                     |      |                                               |   |       



Cash received from
option exercises for the year ended December 31, 2008 was $292. The excess tax benefit realized for the tax deduction from option exercises totaled $380 for the year ended December 31, 2008. This excess tax benefit is included in cash
flows from financing activities in the Consolidated Statement of Cash Flows.



The aggregate intrinsic value in the table above represents the total pretax intrinsic value (the difference between CNX Gas closing stock price on the last trading day of the year ended December 31, 2008 and the
exercise price, multiplied by the number of in-the-money options) that would have been received by the option holders had all option holders exercised their options on December 31, 2008. This amount changes based on the fair market value of CNX
Gas stock. The total intrinsic value of options exercised for the years ended December 31, 2008, 2007 and 2006 was $201, $286, and $0, respectively.



As of December 31, 2008, $1,287 of total unrecognized compensation cost related to unvested options awards is expected to be recognized over a
weighted-average period of 0.60 years.



Restricted Stock
Units



Under the Equity Incentive Plan, CNX Gas
granted certain employees and certain directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. A total of 28,375 restricted stock units were outstanding at December 31, 2008.
Compensation expense will be recognized over the vesting period of the units. The total fair value of restricted stock unit awards that vested during the year was $1,214. For the years ended December 31, 2008, 2007 and 2006, the total fair
value of restricted stock units granted was $600, $480 and $175, respectively.



The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of the grant:



|                                |  |         |   |  |                                     |      
|------------------------------- |  | ------- | - |  | ----------------------------------- | -----
|                                |  | Shares  |   |  | WeightedAverageGrant Date FairValue
|Non-vested at December 31, 2007 |  | 52,310  |   |  | $                                   | 21.04
|Granted                         |  | 14,424  |   |  |                                     | 41.59
|Vested                          |  | (38,359 | ) |  |                                     | 18.51
|                                |  |         |   |  |                                     |      
|Non-Vested at December 31, 2008 |  | 28,375  |   |  | $                                   | 34.91
|                                |  |         |   |  |                                     |      



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(Dollars in thousands, except per share data)



As of December 31, 2008, $436 of total unrecognized compensation cost related to unvested
Restricted Stock Unit (RSU) awards is expected to be recognized over a weighted-average period of 0.67 years.



Long Term Incentive Compensation



CNX Gas also has a long-term incentive program. 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 stock holder return relative to the
stock holder return of a pre-determined peer group of companies. CNX Gas will recognize compensation costs over the requisite service period. The basis of the compensation costs will be re-valued quarterly. As of December 31, 2008, there were
two tranches of PSUs outstanding. The first tranche, awarded in 2006 had 183,280 units outstanding and a performance measurement period from October 11, 2006 to December 31, 2009. The second tranche, awarded in 2008, had 187,382 units
outstanding and a performance measurement period from January 1, 2008 to December 31, 2010. The combined fair value of these awards recorded as a liability at December 31, 2008 was $11,780. Approximately $8,779, $2,231, and $770 of
compensation costs have been recognized for the years ended 2008, 2007, and 2006, respectively.



Note 14Accumulated Other Comprehensive Income:



Components of accumulated other comprehensive income consist of the following:



|                                                             |  |                                       |         |   |                                     |   |      |                                     |  |   |         |  
|------------------------------------------------------------ |  | ------------------------------------- | ------- | - | ----------------------------------- | - | ---- | ----------------------------------- |  | - | ------- | -
|                                                             |  | Change inFair Valueof Cash FlowHedges |         |   | Adjustmentsfor FASBStatementNo. 158 |   |      | AccumulatedOtherComprehensiveIncome | 
|Balance at December 31, 2006                                 |  | $                                     | 1,650   |   |                                     | $ | 760  |                                     |  | $ | 2,410   |  
|Net increase in value of cash flow hedge                     |  |                                       | 23,943  |   |                                     |   |     |                                     |  |   | 23,943  |  
|Reclassification from other comprehensive income to earnings |  |                                       | (19,729 | ) |                                     |   |     |                                     |  |   | (19,729 | )
|Current period adjustment                                    |  |                                       |        |   |                                     |   | (433 | )                                   |  |   | (433    | )
|                                                             |  |                                       |         |   |                                     |   |      |                                     |  |   |         |  
|Balance at December 31, 2007                                 |  |                                       | 5,864   |   |                                     |   | 327  |                                     |  |   | 6,191   |  
|Net increase in value of cash flow hedge                     |  |                                       | 117,699 |   |                                     |   |     |                                     |  |   | 117,699 |  
|Reclassification from other comprehensive income to earnings |  |                                       | 947     |   |                                     |   |     |                                     |  |   | 947     |  
|Current period adjustment                                    |  |                                       |        |   |                                     |   | (33  | )                                   |  |   | (33     | )
|Cumulative effect adjustment prior period                    |  |                                       |        |   |                                     |   | (20  | )                                   |  |   | (20     | )
|                                                             |  |                                       |         |   |                                     |   |      |                                     |  |   |         |  
|Balance at December 31, 2008                                 |  | $                                     | 124,510 |   |                                     | $ | 274  |                                     |  | $ | 124,784 |  
|                                                             |  |                                       |         |   |                                     |   |      |                                     |  |   |         |  



The cash flow hedges
that CNX Gas holds are disclosed in Note 18. The adjustments for FASB Statement No. 158 are disclosed in Note 12.



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Note 15Supplemental Cash Flow Information:



|                                                      |  |                                 |         |   |      |   |        |      |  |   |         |  
|----------------------------------------------------- |  | ------------------------------- | ------- | - | ---- | - | ------ | ---- |  | - | ------- | -
|                                                      |  | For the YearsEnded December 31, |        
|                                                      |  | 2008                            |         |   | 2007 |   |        | 2006 | 
|Net Cash provided from operating activities included: |  |                                 |         |   |      |   |        |      |  |   |         |  
|Interest paid                                         |  | $                               | 7,114   |   |      | $ | 5,328  |      |  | $ | 870     |  
|Income Taxes paid                                     |  | $                               | 63,919  |   |      | $ | 19,220 |      |  | $ | 37,241  |  
|Non-cash investing and financing activities:          |  |                                 |         |   |      |   |        |      |  |   |         |  
|Purchase of Property, Plant and Equipment             |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               | (32,096 | ) |      | $ | 341    |      |  | $ | (12,674 | )
|Change in Liabilities                                 |  | $                               | (32,096 | ) |      | $ | 341    |      |  | $ | (12,674 | )
|Tenant Improvement Allowance                          |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               |        |   |      | $ | (1,109 | )    |  | $ |        |  
|Change in Liabilities                                 |  | $                               |        |   |      | $ | (1,109 | )    |  | $ |        |  
|Businesses Acquired (Note 2)                          |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               | (6,110  | ) |      | $ |       |      |  | $ |        |  
|Change in Liabilities                                 |  | $                               | (6,110  | ) |      | $ |       |      |  | $ |        |  
|Accounting for Asset Retirement Obligations           |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               | (2,143  | ) |      | $ | 3,563  |      |  | $ | 2,027   |  
|Change in Liabilities                                 |  | $                               | (2,143  | ) |      | $ | 3,563  |      |  | $ | 2,027   |  
|Adoption of FIN 48                                    |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               |        |   |      | $ | (4,572 | )    |  | $ |        |  
|Change in Liabilities                                 |  | $                               |        |   |      | $ | (4,572 | )    |  | $ |        |  
|Acquisition of Mineral Rights                         |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               |        |   |      | $ | (6,500 | )    |  | $ |        |  
|Change in Liabilities                                 |  | $                               |        |   |      | $ | (6,500 | )    |  | $ |        |  
|Consolidation of VIE                                  |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               | 680     |   |      | $ | (870   | )    |  | $ |        |  
|Change in Liabilities                                 |  | $                               | 680     |   |      | $ | (870   | )    |  | $ |        |  
|Capital Lease Obligation                              |  |                                 |         |   |      |   |        |      |  |   |         |  
|Change in Assets                                      |  | $                               | (1,874  | ) |      | $ |       |      |  | $ | (66,919 | )
|Change in Liabilities                                 |  | $                               | (1,874  | ) |      | $ |       |      |  | $ | (66,919 | )



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Note 16Concentration of Credit Risk:



CNX Gas markets methane gas for sale primarily to gas wholesalers. Credit is extended based on an evaluation of the
customers financial condition, and generally collateral is not required. A table illustrating sales to individual customers constituting 10% or more of outside sales is as follows:



|                               |  |                               |  |                                      |         |                        |    |   |                                          |   |      
|------------------------------ |  | ----------------------------- |  | ------------------------------------ | ------- | ---------------------- | -- | - | ---------------------------------------- | - | -----
|For the YearEnded December 31, |  | Customer                      |  | Amount For theYear EndedDecember 31, |         | Percent ofOutsideSales |    |   | AccountsReceivableBalance atDecember 31,
|2008                           |  | Sempra Energy                 |  | $                                    | 105,864 |                        | 14 | % |                                          | $ | 7,191
|                               |  | B.P. Energy Company           |  | $                                    | 103,093 |                        | 14 | % |                                          | $ | 8,388
|                               |  | Interstate Gas Supply, Inc.   |  | $                                    | 88,654  |                        | 12 | % |                                          | $ | 6,304
|                               |  |                               |  |                                     
|2007                           |  | B.P. Energy Company           |  | $                                    | 110,517 |                        | 27 | % |                                          | $ | 7,525
|                               |  | Interstate Gas Supply, Inc.   |  | $                                    | 63,489  |                        | 16 | % |                                          | $ | 6,531
|                               |  | Eagle Energy Partners I, L.P. |  | $                                    | 51,116  |                        | 13 | % |                                          | $ | 3,867
|                               |  | Atmos Energy Marketing, LLC   |  | $                                    | 39,121  |                        | 10 | % |                                          | $ | 2,325
|                               |  |                               |  |                                     
|2006                           |  | B.P. Energy Company           |  | $                                    | 89,118  |                        | 23 | % |                                          | $ | 8,950
|                               |  | Interstate Gas Supply, Inc.   |  | $                                    | 55,647  |                        | 14 | % |                                          | $ | 6,767
|                               |  | Eagle Energy Partners I, L.P. |  | $                                    | 54,258  |                        | 14 | % |                                          | $ | 5,742
|                               |  | Conoco-Phillips               |  | $                                    | 45,920  |                        | 12 | % |                                          | $ |     



Note 17Fair Value of
Financial Instruments:



Effective January 1, 2008,
CNX Gas adopted Statement of Financial Accounting Standards 157, Fair Value Measurements (SFAS 157) and Statement of Financial Accounting Standards 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including
an amendment of FASB Statement No. 115 (FAS 159). The adoption of SFAS 157 was not material to CNX Gas. As a result of the adoption, CNX Gas elected not to measure any additional financial assets or liabilities at fair value, other than
those which were recorded at fair value prior to the adoption of SFAS 159.



The financial assets measured at fair value on a recurring basis are summarized below:



|                     |  |                                                         |   |                                   |   |                               |  |   |  
|-------------------- |  | ------------------------------------------------------- | - | --------------------------------- | - | ----------------------------- |  | - | -
|                     |  | Fair Value Measurements at December 31, 2008           
|                     |  | Quoted Prices inActive Markets forIdentical Liabilities |   | SignificantOtherObservable Inputs |   | SignificantUnobservableInputs
|Description          |  | (Level 1)                                               |   | (Level 2)                         |   | (Level 3)                    
|Gas Cash Flow Hedges |  | $                                                       |  |                                   | $ | 206,509                       |  | $ | 



Statement of Financial
Accounting Standards No. 107, Disclosures About Fair Value of Financial Instruments (SFAS 107) requires the disclosure of the estimated fair value of financial instruments including those financial instruments for which the SFAS 159
fair value option was not elected. The following methods and assumptions were used to estimate the fair value of those financial instruments:



Cash and cash equivalents: The carrying amount reported in the balance sheets for cash and cash equivalents approximates its fair value due to the
short maturity of these instruments.



Short-term notes
payable:The carrying amount reported in the balance sheets for short-term notes payable approximates its fair value due to the short-term maturity of these instruments.



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(Dollars in thousands, except per share data)



Long-term debt: The fair values of long-term debt are estimated using discounted cash flow
analyses, based on CNX Gas current incremental borrowing rates for similar types of borrowing arrangements.



The carrying amounts and fair values of financial instruments for which SFAS 159 was not elected are as follows:



|                          |  |                   |         |   |                   |   |         |                |  |   |            |   |  |   |        |  
|------------------------- |  | ----------------- | ------- | - | ----------------- | - | ------- | -------------- |  | - | ---------- | - |  | - | ------ | -
|                          |  | December 31, 2008 |         |   | December 31, 2007 |  
|                          |  | CarryingAmount    |         |   | Fair Value        |   |         | CarryingAmount |  |   | Fair Value |  
|Cash and cash equivalents |  | $                 | 1,926   |   |                   | $ | 1,926   |                |  | $ | 32,048     |   |  | $ | 32,048 |  
|Short-term notes payable  |  | $                 | (72,700 | ) |                   | $ | (72,700 | )              |  | $ |           |   |  | $ |       |  
|Long-term debt            |  | $                 | (19,883 | ) |                   | $ | (16,549 | )              |  | $ | (8,850     | ) |  | $ | (7,951 | )



Note 18Derivative
Instruments:



CNX Gas has entered into derivative
financial instruments, for purposes other than trading, to convert the market prices related to these anticipated sales of natural gas to fixed prices. These instruments are designated as cash flow hedges and extend through 2010. The net fair values
of the outstanding instruments are an asset of $206,509 and an asset of $9,619 at December 31, 2008 and 2007, respectively.



CNX Gas entered into cash flow hedges for natural gas in 2008, 2007 and 2006. Gains or losses related to these derivative instruments were recognized when
the sale of the natural gas affected earnings. The ineffective portion of the changes in the fair value of these contracts was insignificant in 2008, 2007 and 2006.



For these cash flow hedge strategies, the fair values of the derivatives are recorded on the balance sheet. The effective
portions of the changes in fair values of the derivatives are recorded in accumulated other comprehensive income and loss and are reclassified to sales in the period in which earnings are impacted by the hedged items or in the period that the
transaction no longer qualifies as a cash flow hedge. There were no transactions that ceased to qualify as a cash flow hedge in 2008, 2007 or 2006.



Assuming market prices remain constant with prices at December 31, 2008, $91,486 of the net $124,510 gain included in other comprehensive income is
expected to be recognized in earnings over the next 12 months. The remaining net gain is expected to be recognized through 2010.



CNX Gas did not have any derivatives designated as fair value hedges in 2008, 2007 or 2006.



Note 19Commitments and Contingent Liabilities:



CNX Gas is subject to various pending and threatened lawsuits and claims arising in the ordinary course of its business. Certain of the
more significant of these lawsuits and claims are described below. Our current estimates related to these pending claims, individually and in the aggregate, are immaterial to the financial position, results of operations and cash flows of CNX Gas.
However, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CNX Gas.



On February 14, 2007, GeoMet, Inc. and certain of its affiliates filed a
lawsuit against CNX Gas Company LLC and Island Creek Coal Company, a subsidiary of CONSOL Energy, in the Circuit Court for the County of



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(Dollars in thousands, except per share data)



Tazewell, Virginia (Case No. CL07000065-00). The lawsuit alleged that CNX Gas conspired with Island Creek and has violated the Virginia Antitrust
Act and tortuously interfered with GeoMets contractual relations, prospective contracts and business expectancies. CNX Gas and Island Creek filed motions to dismiss all counts of the complaint. On December 19, 2007, the court granted CNX
Gas and Island Creeks motions to dismiss all counts, with leave for GeoMet to file an amended complaint. On March 31, 2008, GeoMet filed an amended complaint. The amended complaint is again against CNX Gas
and Island Creek, but it added CONSOL Energy and Cardinal States Gathering Company as additional defendants. The amended complaint restates allegations that CNX Gas, Island Creek and now CONSOL Energy and Cardinal States Gathering
Company violated the Virginia Antitrust Act and tortuously interfered with GeoMets contractual relations, prospective contracts and business expectancies. The amended complaint seeks injunctive relief, compensatory damages of
$385,600 and treble damages. CNX Gas continues to believe this lawsuit to be without merit and intends to vigorously defend it. CNX Gas action seeking to dismiss GeoMets complaint is pending. We cannot predict the ultimate outcome
of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.



On January 7, 2009, CNX Gas received a civil investigative demand
for information and documents from the Attorney General of the Commonwealth of Virginia regarding the companys exploration, production, transportation and sale of coalbed methane gas in Virginia. According to the request,
the Attorney General is investigating whether the company may have violated the Virginia Antitrust Act. The request for information does not constitute the commencement of legal proceedings and does not make any specific
allegations against the company. CNX Gas does not believe that it has violated the Virginia Antitrust Act and the company intends to cooperate with the Attorney Generals investigation.



The Company is a party to a case captioned Earl Kennedy et. al v. CNX Gas and
CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania (Case No. 225 of 2007). The lawsuit alleges that CNX Gas and CONSOL Energy conspired and were unjustly enriched, trespassed, converted, and
committed fraud relating to gas and other minerals allegedly belonging to Mr. Kennedy. The suit also seeks to overturn existing law as to the ownership of coalbed methane in Pennsylvania. The complaint, as amended, seeks injunctive relief,
including having us be removed from the property, quiet title and compensatory damages of $20,000. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it. We cannot predict the ultimate outcome of this litigation;
however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations, or cash flows of CNX Gas.



In April 2005, Buchanan County, Virginia (through its Board of Supervisors
and Commissioner of Revenue) filed a Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code § 8.01-184 against CNX Gas Company LLC in the Circuit Court of the County of Buchanan (Case No. CL05000149-00)
for the year 2002; the county has since filed and served two substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that our calculation of the license tax on the basis of the wellhead
value (sales price less post production costs) rather than the sales price is improper. For the period from 1999 through mid 2002, we paid the tax on the basis of the sales price, but we have filed a claim for a refund for these years. Since 2002,
we have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability reflected in Other Liabilities on our balance sheet in an amount based on the difference between our
calculation of the tax and Buchanan Countys calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. However,
it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of operations or cash flows of CNX Gas.



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(Dollars in thousands, except per share data)



In 2004, Yukon Pocahontas Coal Company, Buchanan Coal Company and Sayers-Pocahontas Coal Company
filed a complaint against Consolidation Coal Company (CCC), a subsidiary of CONSOL Energy in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from
mining activities at CCCs Buchanan Mine into nearby void spaces in the mine of one of CONSOL Energys other subsidiaries, Island Creek Coal Company (ICCC). CCC believes that it had, and continues to have, the right to store
water in these void areas. On September 21, 2006, the plaintiffs filed an amended complaint in the Circuit Court of Buchanan County, Virginia (Case No. CL04-91) which, among other things, added CONSOL Energy, ICCC and CNX Gas Company LLC
as additional defendants. The amended complaint alleges, among other things, that CNX Gas, as lessee and operator under certain coalbed methane gas leases from plaintiffs, had a duty to prevent CCC from depositing water into the mine voids and
failed to do so. The proposed amended complaint seeks $150,000 in damages from the additional defendants, plus costs, interest and attorneys fees. CNX Gas denies that it has any liability in this matter and intends to vigorously defend this
action. We cannot predict the ultimate outcome of this litigation; however, it is reasonably possible that the ultimate liabilities in the future with respect to these lawsuits and claims may be material to the financial position, results of
operations or cash flows of CNX Gas.



In 1999, CNX Gas was
named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty owners. The claim of underpayment of royalties related to
the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post-production expenses of gathering, compression and transportation. CNX Gas was ordered to pay, and
subsequently paid, damages to the group of royalty owners that brought the suit. A final payment was subsequently made to the plaintiffs to adjust all royalties owed to the plaintiffs for subsequent periods, which effectively settled this case. CNX
Gas recognized an estimated liability for other similarly situated plaintiffs who could bring similar claims. This amount is included in Other Liabilities on the balance sheet and is evaluated quarterly. CNX Gas believes that the final resolution of
this matter will not have a material effect on our financial position, results of operations or cash flows.



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(Dollars in thousands, except per share data)



At December 31, 2008, CNX Gas has provided the following financial guarantees, unconditional
purchase obligations and letters of credit to certain third parties, as described by major category in the following table. These amounts represent the maximum potential total of future payments that we could be required to make under these
instruments. These amounts have not been reduced for potential recoveries under recourse or collateralization provisions. Generally, recoveries under reclamation bonds would be limited to the extent of the work performed at the time of the default.
No amounts related to these financial guarantees and letters of credit are recorded as liabilities on the financial statements. CNX Gas management believes that these guarantees will expire without being funded, and therefore the commitments will
not have a material adverse effect on financial condition.



|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|----------------------- |  | ---------------- | ------- | --------------- | - | --------- |  | --------- | -- | ------------- | - | ------- |  | - | -
|                        |  | AmountsCommitted |         | Less than1 Year |   | 1-3 Years |  | 3-5 Years |    | Beyond5 Years
|Letters of Credit:      |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Gas                     |  | $                | 14,933  |                 | $ | 14,933    |  | $         |   |               | $ |        |  | $ | 
|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Total Letters of Credit |  | $                | 14,933  |                 | $ | 14,933    |  | $         |   |               | $ |        |  | $ | 
|Surety Bonds:           |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Environmental           |  | $                | 1,544   |                 | $ | 1,544     |  | $         |   |               | $ |        |  | $ | 
|Other                   |  |                  | 2,728   |                 |   | 2,663     |  |           | 65 |               |   |        |  |   | 
|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Total Surety Bonds      |  | $                | 4,272   |                 | $ | 4,207     |  | $         | 65 |               | $ |        |  | $ | 
|Other:                  |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Guarantees              |  |                  | 279,741 |                 |   | 29,741    |  |           |   |               |   | 250,000 |  |   | 
|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Total Guarantees        |  | $                | 279,741 |                 | $ | 29,741    |  | $         |   |               | $ | 250,000 |  | $ | 
|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  
|Total Commitments       |  | $                | 298,946 |                 | $ | 48,881    |  | $         | 65 |               | $ | 250,000 |  | $ |  
|                        |  |                  |         |                 |   |           |  |           |    |               |   |         |  |   |  



Financial guarantees
have primarily been provided to support various performance bonds related to land usage, pipeline usage and restorative issues. Other contingent liabilities have been extended to support insurance policies, legal matters and other items necessary in
the normal course of business. CNX Gas has also provided financial guarantees for the purchase and delivery of gas to various counterparties. CNX Gas and subsidiaries have executed a Supplemental Indenture and are guarantors of CONSOL Energys
7.875% notes due March 1, 2012 in the principal amount of $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture governing CONSOL Energys 7.875% notes would require CNX Gas to
ratably secure the notes.



CONSOL Energy has also provided
certain parental guarantees related to gas purchases, gas sales and firm transportation associated with CNX Gas. CNX Gas anticipates that these parental guarantees will be transferred from CONSOL Energy to CNX Gas over time. CNX Gas management
believes these parental guarantees will also expire without being funded, and therefore the commitments will not have a material adverse effect on our financial condition.



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(Dollars in thousands, except per share data)



CNX Gas enters into long-term unconditional purchase obligations to procure firm transportation and
gas drilling services. These purchase obligations are not recorded on the Consolidated Balance Sheet. As of December 31, 2008, the amounts of purchase obligations for each of the next five years were as follows:



|                           |  |        |        
|-------------------------- |  | ------ | -------
|Year Ended December 31,    |  | Amount
|2009                       |  | $      | 22,177 
|2010                       |  |        | 24,014 
|2011                       |  |        | 17,249 
|2012                       |  |        | 16,354 
|2013                       |  |        | 15,881 
|Thereafter                 |  |        | 239,196
|                           |  |        |        
|Total purchase obligations |  | $      | 334,871
|                           |  |        |        



Note 20Segment Information:



The principal activity of CNX Gas is to produce methane
gas for sale primarily to gas wholesalers. In the current year, CNX Gas implemented a new internal segment reporting method to align segment results to how management assesses the operations. As a result, some charges that were previously reflected
in Central Appalachia and Northern Appalachia segments have been reclassified to the Other segment. Also, some corporate charges that were previously reflected in the Central Appalachia and Northern Appalachia segment are now reported as Corporate
items and reflected in the reconciliation between Segment Earnings (Loss) Before Income Tax to Total Earnings (Loss) Before Income Tax. Prior year information has also been changed to eliminate intersegment revenue and allocate Earnings Before
Income Taxes between Central Appalachia and Northern Appalachia. CNX Gas has three reportable segments: Central Appalachia, Northern Appalachia and Other. Each of these reportable segments includes a number of operating segments. For the year ended
December 31, 2008, the Central Appalachia segment includes the following operating segments: Virginia Operations, Cardinal States Gathering and Knox Energy. For the year ended December 31, 2008, the Northern Appalachia segment includes the
following operating segments: Mountaineer, Nittany and Panther. The Other segment includes other operating segments that fall outside the reported geographic areas and various other activities assigned to operations but not allocated to an
individual operating segment. Operating profit for each segment is based on sales less identifiable operating and non-operating expenses.



Reportable segment results for the year ended December 31, 2008 are:



|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|---------------------------------------- |  | ----------------- | --------- | ------------------ | - | ------- |  | --------- | ------ | --------- | - | --------- | ------------ | - | ------- | - |  | - | --------- | ---
|                                         |  | CentralAppalachia |           | NorthernAppalachia |   | Other   |  | Total Gas |        | Corporate |   |           | Consolidated |  
|Salesoutside                            |  | $                 | 569,051   |                    | $ | 106,668 |  | $         | 3,074  |           | $ | 678,793   |              | $ |        |   |  | $ | 678,793   | (A)
|Salesrelated parties                    |  |                   | 9,495     |                    |   | 37      |  |           |       |           |   | 9,532     |              |   |        |   |  |   | 9,532     |    
|Salesroyalty interest gas               |  |                   | 78,485    |                    |   | 817     |  |           |       |           |   | 79,302    |              |   |        |   |  |   | 79,302    |    
|Salespurchased gas                      |  |                   | 8,074     |                    |   | 390     |  |           |       |           |   | 8,464     |              |   |        |   |  |   | 8,464     |    
|Other revenue                            |  |                   | 11,056    |                    |   | 1       |  |           | 1,545  |           |   | 12,602    |              |   | 728     |   |  |   | 13,330    |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|Total Revenue and Other Income           |  | $                 | 676,161   |                    | $ | 107,913 |  | $         | 4,619  |           | $ | 788,693   |              | $ | 728     |   |  | $ | 789,421   |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|Earnings Before Income Taxes(B)          |  | $                 | 383,247   |                    | $ | 37,197  |  | $         | 379    |           | $ | 420,823   |              | $ | (28,094 | ) |  | $ | 392,729   |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|Segment assets                           |  | $                 | 1,416,986 |                    | $ | 562,336 |  | $         | 88,137 |           | $ | 2,067,459 |              | $ | 57,514  |   |  | $ | 2,124,973 |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|Depreciation, depletion and amortization |  | $                 | 56,734    |                    | $ | 12,137  |  | $         | 1,139  |           | $ | 70,010    |              | $ |        |   |  | $ | 70,010    |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    
|Capital expenditures                     |  | $                 | 256,576   |                    | $ | 290,130 |  | $         | 13,957 |           | $ | 560,663   |              | $ |        |   |  | $ | 560,663   |    
|                                         |  |                   |           |                    |   |         |  |           |        |           |   |           |              |   |         |   |  |   |           |    



|(A) | Included in the Central Appalachia segment are sales of $105,864 to Sempra Energy, $103,093 to B.P. Energy Company and $88,654 to Interstate Gas Supply, Inc.
|--- | -------------------------------------------------------------------------------------------------------------------------------------------------------------

|(B) | Includes equity in earnings (loss) of unconsolidated affiliates of $223 for Central Appalachia.
|--- | -----------------------------------------------------------------------------------------------



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Reportable segment results for the year ended December 31, 2007 are:



|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------- | --------- | ------------------ | - | ------- | ----- |  | - | --------- | - | --------- | - | --------- | ------------ | - | ------- | - |  | - | --------- | ---
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  | CentralAppalachia |           | NorthernAppalachia |   |         | Other |  |   | Total Gas |   | Corporate |   |           | Consolidated |  
|Salesoutside                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | $                 | 374,663   |                    | $ | 30,070  |       |  | $ | 102       |   |           | $ | 404,835   |              | $ |        |   |  | $ | 404,835   | (C)
|Salesrelated parties                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |                   | 11,564    |                    |   | 54      |       |  |   |          |   |           |   | 11,618    |              |   |        |   |  |   | 11,618    |    
|Salesroyalty interest gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |  |                   | 46,169    |                    |   | 417     |       |  |   |          |   |           |   | 46,586    |              |   |        |   |  |   | 46,586    |    
|Salespurchased gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                   | 7,628     |                    |   |        |       |  |   |          |   |           |   | 7,628     |              |   |        |   |  |   | 7,628     |    
|Other revenue                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                   | 4,851     |                    |   |        |       |  |   | 55        |   |           |   | 4,906     |              |   | 3,909   |   |  |   | 8,815     |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Total Revenue and Other Income                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |  | $                 | 444,875   |                    | $ | 30,541  |       |  | $ | 157       |   |           | $ | 475,573   |              | $ | 3,909   |   |  | $ | 479,482   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Earnings Before Income Taxes(D)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  | $                 | 240,737   |                    | $ | (4,438  | )     |  | $ | (1,802    | ) |           | $ | 234,497   |              | $ | (13,858 | ) |  | $ | 220,639   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Segment assets(E)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  | $                 | 1,047,325 |                    | $ | 203,923 |       |  | $ | 71,558    |   |           | $ | 1,322,806 |              | $ | 57,897  |   |  | $ | 1,380,703 |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Depreciation, depletion and amortization                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |  | $                 | 41,835    |                    | $ | 6,152   |       |  | $ | 974       |   |           | $ | 48,961    |              | $ |        |   |  | $ | 48,961    |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Capital expenditures                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |  | $                 | 157,313   |                    | $ | 115,374 |       |  | $ | 84,512    |   |           | $ | 357,199   |              | $ |        |   |  | $ | 357,199   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|(C)   Included in the Central Appalachia segment are sales of $110,517 to B.P. Energy Company, $63,489 to Interstate Gas Supply, Inc. and $39,121 to Atmos Energy Marketing, LLC. Included in Central
Appalachia and Northern Appalachia segments are sales of $51,116 to Eagle Energy Partners I, L.P. (D)   Includes equity in earnings (loss) of unconsolidated affiliates of $2,058 for Central Appalachia. (E)   Includes investments in unconsolidated equity affiliates of $3,408 for Central Appalachia.  Reportable segment results for the year ended December 31, 2006 are: | 
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  | CentralAppalachia |           | NorthernAppalachia |   |         | Other |  |   | Total Gas |   | Corporate |   |           | Consolidated |  
|Salesoutside                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  | $                 | 363,241   |                    | $ | 21,815  |       |  | $ |          |   |           | $ | 385,056   |              | $ |        |   |  | $ | 385,056   | (F)
|Salesrelated parties                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  |  |                   | 8,392     |                    |   | 98      |       |  |   |          |   |           |   | 8,490     |              |   |        |   |  |   | 8,490     |    
|Salesroyalty interest gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             |  |                   | 50,878    |                    |   | 176     |       |  |   |          |   |           |   | 51,054    |              |   |        |   |  |   | 51,054    |    
|Salespurchased gas                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    |  |                   | 43,973    |                    |   |        |       |  |   |          |   |           |   | 43,973    |              |   |        |   |  |   | 43,973    |    
|Other revenue                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          |  |                   | 22,542    |                    |   | 696     |       |  |   |          |   |           |   | 23,238    |              |   | 3,026   |   |  |   | 26,264    |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Total Revenue and Other Income                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         |  | $                 | 489,026   |                    | $ | 22,785  |       |  | $ |          |   |           | $ | 511,811   |              | $ | 3,026   |   |  | $ | 514,837   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Earnings Before Income Taxes(G)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        |  | $                 | 259,391   |                    | $ | 4,064   |       |  | $ |          |   |           | $ | 263,455   |              | $ | (7,015  | ) |  | $ | 256,440   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Segment assets(H)                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      |  | $                 | 943,222   |                    | $ | 79,846  |       |  | $ |          |   |           | $ | 1,023,068 |              | $ | 131,933 |   |  | $ | 1,155,001 |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Depreciation, depletion and amortization                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                               |  | $                 | 35,190    |                    | $ | 2,809   |       |  | $ |          |   |           | $ | 37,999    |              | $ |        |   |  | $ | 37,999    |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    
|Capital expenditures                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   |  | $                 | 122,287   |                    | $ | 31,956  |       |  | $ |          |   |           | $ | 154,243   |              | $ |        |   |  | $ | 154,243   |    
|                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       |  |                   |           |                    |   |         |       |  |   |           |   |           |   |           |              |   |         |   |  |   |           |    



|(F) | Included in the Central Appalachia segment are sales of $89,118 to B.P. Energy Company, $55,647 to Interstate Gas Supply, Inc. and $45,920 to Conoco-Phillips. Included in the
Central Appalachia and Northern Appalachia segments are sales of $54,258 to Eagle Energy Partners I, L.P.
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

|(G) | Includes equity in earnings (loss) of unconsolidated affiliates of $1,405 for Central Appalachia.
|--- | -------------------------------------------------------------------------------------------------

|(H) | Includes investments in unconsolidated equity affiliates of $27,523 for Central Appalachia.
|--- | -------------------------------------------------------------------------------------------



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Reconciliation of Segment Information to Consolidated Amounts:



Earnings Before Income Taxes:



|                                                                                                        |  |                                 |           |   |      |   |           |      |  |   |           |  
|------------------------------------------------------------------------------------------------------- |  | ------------------------------- | --------- | - | ---- | - | --------- | ---- |  | - | --------- | -
|                                                                                                        |  | For the YearsEnded December 31, |          
|                                                                                                        |  | 2008                            |           |   | 2007 |   |           | 2006 | 
|Segment earnings before income taxes for total reportable business segments                             |  | $                               | 420,823   |   |      | $ | 234,497   |      |  | $ | 263,455   |  
|Equity in earnings (losses) of Buchanan Generation                                                      |  |                                 | 328       |   |      |   | 116       |      |  |   | (427      | )
|Incentive Compensation                                                                                  |  |                                 | (7,988    | ) |      |   | (5,659    | )    |  |   | (4,511    | )
|Compensation from restricted stock unit grants, stock option expense and performance share unit expense |  |                                 | (12,157   | ) |      |   | (5,491    | )    |  |   | (4,504    | )
|Bank fees                                                                                               |  |                                 | (857      | ) |      |   | (1,011    | )    |  |   | (1,017    | )
|Interest income (expense), net                                                                          |  |                                 | (7,420    | ) |      |   | (1,813    | )    |  |   | 3,444     |  
|                                                                                                        |  |                                 |           |   |      |   |           |      |  |   |           |  
|Earnings before income taxes                                                                            |  | $                               | 392,729   |   |      | $ | 220,639   |      |  | $ | 256,440   |  
|                                                                                                        |  |                                 |           |   |      |   |           |      |  |   |           |  
|Total Assets:                                                                                           |  |                                 |           |   |      |   |           |      |  |   |           |  
|                                                                                                        | 
|                                                                                                        |  | December 31,                    |          
|                                                                                                        |  | 2008                            |           |   | 2007 |   |           | 2006 | 
|Segment assets for total reportable business segments                                                   |  | $                               | 2,067,459 |   |      | $ | 1,322,806 |      |  | $ | 1,023,068 |  
|Items excluded from segment assets:                                                                     |  |                                 |           |   |      |   |           |      |  |   |           |  
|Cash and other investments                                                                              |  |                                 | 2,008     |   |      |   | 32,048    |      |  |   | 107,173   |  
|Recoverable income taxes                                                                                |  |                                 | 30,302    |   |      |   | 972       |      |  |   |          |  
|Investment in Buchanan Generation                                                                       |  |                                 | 25,204    |   |      |   | 24,877    |      |  |   | 24,760    |  
|                                                                                                        |  |                                 |           |   |      |   |           |      |  |   |           |  
|Total Consolidated Assets                                                                               |  | $                               | 2,124,973 |   |      | $ | 1,380,703 |      |  | $ | 1,155,001 |  
|                                                                                                        |  |                                 |           |   |      |   |           |      |  |   |           |  



All of CNX Gas
revenues and property, plant and equipment are attributable to or located in the United States.



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Other Supplemental InformationSupplemental Gas Data (unaudited):



The following information was prepared in accordance with Statement of
Financial Accounting Standards No. 69, Disclosures About Oil and Gas Producing Activities and related accounting rules:



Capitalized Costs:



|                                                                                                           |  |                    |           |   |      |   |           |  
|---------------------------------------------------------------------------------------------------------- |  | ------------------ | --------- | - | ---- | - | --------- | -
|                                                                                                           |  | As of December 31, |          
|                                                                                                           |  | 2008               |           |   | 2007 |  
|Proved Properties:                                                                                         |  | $                  | 121,605   |   |      | $ | 104,515   |  
|Unproved Properties                                                                                        |  |                    | 220,848   |   |      |   | 101,680   |  
|Wells and Related Equipment                                                                                |  |                    | 1,001,381 |   |      |   | 698,600   |  
|Gathering Assets                                                                                           |  |                    | 740,396   |   |      |   | 596,173   |  
|                                                                                                           |  |                    |           |   |      |   |           |  
|Total Property, Plant and Equipment                                                                        |  |                    | 2,084,230 |   |      |   | 1,500,968 |  
|Accumulated Depreciation, Depletion and Amortization                                                       |  |                    | (319,959  | ) |      |   | (252,779  | )
|                                                                                                           |  |                    |           |   |      |   |           |  
|Net Capitalized Costs                                                                                      |  | $                  | 1,764,271 |   |      | $ | 1,248,189 |  
|                                                                                                           |  |                    |           |   |      |   |           |  
|Proportionate Share of Gas Producing Net Property, Plant and Equipment of Unconsolidated Equity Affiliates |  | $                  |          |   |      | $ | 28,581    |  
|                                                                                                           |  |                    |           |   |      |   |           |  



Costs incurred for
Property Acquisition, Exploration and Development (*):



|                      |  |                                  |         |                  |   |                        |  |                  |         |                        |   |                  |  |   |         |  |   |      
|--------------------- |  | -------------------------------- | ------- | ---------------- | - | ---------------------- |  | ---------------- | ------- | ---------------------- | - | ---------------- |  | - | ------- |  | - | -----
|                      |  | For the Years Ended December 31,
|                      |  | 2008                             |         | 2007             |   | 2006                  
|                      |  | ConsolidatedOperations           |         | EquityAffiliates |   | ConsolidatedOperations |  | EquityAffiliates |         | ConsolidatedOperations |   | EquityAffiliates
|Property acquisitions |  |                                  |         |                  |   |                        |  |                  |         |                        |   |                  |  |   |         |  |   |      
|Proved Properties     |  | $                                | 17,090  |                  | $ |                       |  | $                | 33,205  |                        | $ |                 |  | $ | 8,797   |  | $ |     
|Unproved Properties   |  |                                  | 119,168 |                  |   |                       |  |                  | 80,313  |                        |   |                 |  |   | 765     |  |   |     
|Development           |  |                                  | 378,119 |                  |   |                       |  |                  | 257,935 |                        |   |                 |  |   | 151,774 |  |   |     
|Exploration           |  |                                  | 68,495  |                  |   |                       |  |                  | 16,503  |                        |   |                 |  |   | 832     |  |   | 2,334
|                      |  |                                  |         |                  |   |                        |  |                  |         |                        |   |                  |  |   |         |  |   |      
|Total                 |  | $                                | 582,872 |                  | $ |                       |  | $                | 387,956 |                        | $ |                 |  | $ | 162,168 |  | $ | 2,334
|                      |  |                                  |         |                  |   |                        |  |                  |         |                        |   |                  |  |   |         |  |   |      



|(*) | Includes costs incurred whether capitalized or expensed
|--- | -------------------------------------------------------



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NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



Results of Operations for Producing Activities:



|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|------------------------------------------------------------------------------------- |  | -------------------------------- | --------- | - | ---------------- | - | ------ | ---------------------- |  | - | ---------------- | - |  | ---------------------- | ----- | - | ---------------- | - | --------- | - |  | - | ----- | -
|                                                                                      |  | For the Years Ended December 31, |          
|                                                                                      |  | 2008                             |           |   | 2007             |   |        | 2006                   | 
|                                                                                      |  | ConsolidatedOperations           |           |   | EquityAffiliates |   |        | ConsolidatedOperations |  |   | EquityAffiliates |   |  | ConsolidatedOperations |       |   | EquityAffiliates |  
|Production Revenue                                                                    |  | $                                | 688,325   |   |                  | $ |       |                        |  | $ | 416,452          |   |  | $                      | 2,755 |   |                  | $ | 393,649   |   |  | $ | 1,913 |  
|Royalty Interest Gas Revenue                                                          |  |                                  | 79,302    |   |                  |   |       |                        |  |   | 46,586           |   |  |                        | 294   |   |                  |   | 51,054    |   |  |   | 446   |  
|Purchased Gas Revenue                                                                 |  |                                  | 8,464     |   |                  |   |       |                        |  |   | 7,628            |   |  |                        | 201   |   |                  |   | 43,973    |   |  |   | 356   |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Total Revenue                                                                         |  |                                  | 776,091   |   |                  |   |       |                        |  |   | 470,666          |   |  |                        | 3,250 |   |                  |   | 488,676   |   |  |   | 2,715 |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Lifting Costs                                                                         |  |                                  | 67,653    |   |                  |   |       |                        |  |   | 38,721           |   |  |                        | 679   |   |                  |   | 33,357    |   |  |   | 480   |  
|Gathering Costs                                                                       |  |                                  | 83,752    |   |                  |   |       |                        |  |   | 61,798           |   |  |                        | 630   |   |                  |   | 58,102    |   |  |   | 359   |  
|Royalty Expense                                                                       |  |                                  | 74,041    |   |                  |   |       |                        |  |   | 40,011           |   |  |                        | 294   |   |                  |   | 41,998    |   |  |   | 446   |  
|Other Costs                                                                           |  |                                  | 34,078    |   |                  |   |       |                        |  |   | 19,772           |   |  |                        | 646   |   |                  |   | 12,876    |   |  |   | 541   |  
|Purchased Gas Costs                                                                   |  |                                  | 8,175     |   |                  |   |       |                        |  |   | 7,162            |   |  |                        | 165   |   |                  |   | 44,843    |   |  |   | 299   |  
|DD&A                                                                                  |  |                                  | 70,010    |   |                  |   |       |                        |  |   | 48,961           |   |  |                        | 294   |   |                  |   | 37,999    |   |  |   | 512   |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Total Costs                                                                           |  |                                  | 337,709   |   |                  |   |       |                        |  |   | 216,425          |   |  |                        | 2,708 |   |                  |   | 229,175   |   |  |   | 2,637 |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Pre-tax Operating Income                                                              |  |                                  | 438,382   |   |                  |   |       |                        |  |   | 254,241          |   |  |                        | 542   |   |                  |   | 259,501   |   |  |   | 78    |  
|Income Taxes                                                                          |  |                                  | 171,407   |   |                  |   |       |                        |  |   | 98,595           |   |  |                        | 210   |   |                  |   | 97,728    |   |  |   | 29    |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Results of Operations for Producing Activities excluding Corporate and Interest Costs |  | $                                | 266,975   |   |                  | $ |       |                        |  | $ | 155,646          |   |  | $                      | 332   |   |                  | $ | 161,773   |   |  | $ | 49    |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Net Reserve Quantity (mmcfe)                                                          |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Beginning Reserves(a)                                                                 |  |                                  | 1,339,909 |   |                  |   | 3,584  |                        |  |   | 1,263,293        |   |  |                        | 2,200 |   |                  |   | 1,127,724 |   |  |   | 2,672 |  
|Revisions(b)                                                                          |  |                                  | (30,828   | ) |                  |   |       |                        |  |   | (25,036          | ) |  |                        | 221   |   |                  |   | 109,116   |   |  |   | (584  | )
|Extensions and Discoveries(c)                                                         |  |                                  | 182,701   |   |                  |   |       |                        |  |   | 145,834          |   |  |                        | 1,484 |   |                  |   | 82,363    |   |  |   | 337   |  
|Production                                                                            |  |                                  | (76,562   | ) |                  |   |       |                        |  |   | (57,928          | ) |  |                        | (321  | ) |                  |   | (55,910   | ) |  |   | (225  | )
|Acquisition of Remaining Interest in Equity Affiliate                                 |  |                                  | 3,584     |   |                  |   | (3,584 | )                      |  |   |                 |   |  |                        |      |   |                  |   |          |   |  |   |      |  
|Purchases of Reserves In-Place                                                        |  |                                  | 3,242     |   |                  |   |       |                        |  |   | 13,746           |   |  |                        |      |   |                  |   |          |   |  |   |      |  
|Sales of Reserves In-Place                                                            |  |                                  |          |   |                  |   |       |                        |  |   |                 |   |  |                        |      |   |                  |   |          |   |  |   |      |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Ending Reserves                                                                       |  |                                  | 1,422,046 |   |                  |   |       |                        |  |   | 1,339,909        |   |  |                        | 3,584 |   |                  |   | 1,263,293 |   |  |   | 2,200 |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Proved Developed Reserves:                                                            |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|Beginning of Period                                                                   |  |                                  | 667,726   |   |                  |   | 3,584  |                        |  |   | 609,700          |   |  |                        | 2,200 |   |                  |   | 549,574   |   |  |   | 2,672 |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  
|End of Period                                                                         |  |                                  | 783,290   |   |                  |   |       |                        |  |   | 667,726          |   |  |                        | 3,584 |   |                  |   | 609,700   |   |  |   | 2,200 |  
|                                                                                      |  |                                  |           |   |                  |   |        |                        |  |   |                  |   |  |                        |       |   |                  |   |           |   |  |   |       |  



|(a) | Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission Rule 4.10(a) of Regulation S-X. Generally, these reserves would be
commercially recovered under current economic conditions, operating methods and government regulations. CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates and
timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available. Proved oil and gas reserves are estimated quantities of natural gas and CBM gas which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with
existing equipment and operating methods.
|--- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



|(b) | Revisions are primarily due to the lower pricing used at December 31, 2008 for reserve estimates.
|--- | -------------------------------------------------------------------------------------------------

|(c) | Extensions and discoveries are the result of additional drilling activities which bring in offset locations as proved reserves. Additionally, they are the result of state oil and
gas boards approval of additional well locations.
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



CNX Gas proved gas reserves are located in the United States.



Standardized Measure of Discounted Future Net Cash Flows:



The following information has been prepared in accordance with the provisions of Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activities. This statement
requires the standardized measure of discounted future net cash flows to be based on year-end sales prices, costs and statutory income tax rates and a 10 percent annual discount rate. Because prices used in the calculation are as of the end of the
period, the standardized measure could vary significantly from year to year based on the market conditions at that specific date.



The projections should not be viewed as realistic estimates of future cash flows, nor should the standardized measure be interpreted as
representing current value to CNX Gas. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary
significantly from those used; and actual costs may vary. CNX Gas investment and operating decisions are not based on the information presented, but on a wide range of reserve estimates that include probable as well as proved reserves and on
different price and cost assumptions.



The standardized measure
is intended to provide a better means for comparing the value of CNX Gas proved reserves at a given time with those of other gas producing companies than is provided by a comparison of raw proved reserve quantities.



|                                                        |  |              |            |   |      |   |            |      |  |   |            |  
|------------------------------------------------------- |  | ------------ | ---------- | - | ---- | - | ---------- | ---- |  | - | ---------- | -
|                                                        |  | December 31, |           
|                                                        |  | 2008         |            |   | 2007 |   |            | 2006 | 
|Future Cash Flows:                                      |  |              |            |   |      |   |            |      |  |   |            |  
|Revenues                                                |  | $            | 8,856,817  |   |      | $ | 9,509,665  |      |  | $ | 7,105,265  |  
|Production costs                                        |  |              | (3,525,902 | ) |      |   | (3,004,619 | )    |  |   | (2,568,731 | )
|Development costs                                       |  |              | (793,592   | ) |      |   | (636,436   | )    |  |   | (552,114   | )
|Income tax expense                                      |  |              | (1,713,713 | ) |      |   | (2,259,415 | )    |  |   | (1,500,533 | )
|                                                        |  |              |            |   |      |   |            |      |  |   |            |  
|Future Net Cash Flows                                   |  |              | 2,823,610  |   |      |   | 3,609,195  |      |  |   | 2,483,887  |  
|Discounted to present value at a 10% annual rate        |  |              | (1,605,176 | ) |      |   | (2,219,655 | )    |  |   | (1,548,996 | )
|                                                        |  |              |            |   |      |   |            |      |  |   |            |  
|Total standardized measure of discounted net cash flows |  | $            | 1,218,434  |   |      | $ | 1,389,540  |      |  | $ | 934,891    |  
|                                                        |  |              |            |   |      |   |            |      |  |   |            |  



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



The following are the principal sources of change in the standardized measure of discounted future
net cash flows during:



|                                                                                                         |  |                        |           |   |                  |   |        |                        |  |   |                  |   |  |                        |        |   |                  |   |            |   |  |   |         |  
|-------------------------------------------------------------------------------------------------------- |  | ---------------------- | --------- | - | ---------------- | - | ------ | ---------------------- |  | - | ---------------- | - |  | ---------------------- | ------ | - | ---------------- | - | ---------- | - |  | - | ------- | -
|                                                                                                         |  | December 31,           |          
|                                                                                                         |  | 2008                   |           |   | 2007             |   |        | 2006                   | 
|                                                                                                         |  | ConsolidatedOperations |           |   | EquityAffiliates |   |        | ConsolidatedOperations |  |   | EquityAffiliates |   |  | ConsolidatedOperations |        |   | EquityAffiliates |  
|Balance at Beginning of Period                                                                           |  | $                      | 1,384,983 |   |                  | $ | 4,557  |                        |  | $ | 933,186          |   |  | $                      | 1,705  |   |                  | $ | 1,865,097  |   |  | $ | 5,697   |  
|Net changes in sales prices and production costs                                                         |  |                        | (676,358  | ) |                  |   |        |                        |  |   | 1,681,550        |   |  |                        | 7,356  |   |                  |   | (5,327,975 | ) |  |   | (13,550 | )
|Sales net of production costs                                                                            |  |                        | (438,382  | ) |                  |   |        |                        |  |   | (207,688         | ) |  |                        | (1,122 | ) |                  |   | (435,909   | ) |  |   | (2,265  | )
|Net change due to revisions in quantity estimates                                                        |  |                        | (63,547   | ) |                  |   |        |                        |  |   | 479,618          |   |  |                        | 5,959  |   |                  |   | 1,495,140  |   |  |   | (2,486  | )
|Net change due to acquisition                                                                            |  |                        | 4,158     |   |                  |   |        |                        |  |   | 2,840            |   |  |                        |       |   |                  |   |           |   |  |   |        |  
|Acquisition of Remaining Interest in Equity Affiliate                                                    |  |                        | 4,557     |   |                  |   | (4,557 | )                      |  |   |                  |   |  |                        |        |   |                  |   |            |   |  |   |         |  
|Development costs incurred during the period                                                             |  |                        | 378,119   |   |                  |   |        |                        |  |   | 257,935          |   |  |                        |       |   |                  |   | 151,774    |   |  |   |        |  
|Difference in previously estimated development costs compared to actual costs incurred during the period |  |                        | (136,742  | ) |                  |   |        |                        |  |   | (87,408          | ) |  |                        |       |   |                  |   | (40,466    | ) |  |   |        |  
|Changes in estimated future development costs                                                            |  |                        | (398,534  | ) |                  |   |        |                        |  |   | (254,635         | ) |  |                        | (214   | ) |                  |   | (241,095   | ) |  |   | (12     | )
|Net change in future income taxes                                                                        |  |                        | 545,702   |   |                  |   |        |                        |  |   | (754,209         | ) |  |                        | (4,673 | ) |                  |   | 1,743,570  |   |  |   | 7,162   |  
|Accretion of discount and other                                                                          |  |                        | 614,478   |   |                  |   |        |                        |  |   | (666,206         | ) |  |                        | (4,454 | ) |                  |   | 1,723,050  |   |  |   | 7,159   |  
|                                                                                                         |  |                        |           |   |                  |   |        |                        |  |   |                  |   |  |                        |        |   |                  |   |            |   |  |   |         |  
|Total Discounted Cash Flow at End of Period                                                              |  | $                      | 1,218,434 |   |                  | $ |       |                        |  | $ | 1,384,983        |   |  | $                      | 4,557  |   |                  | $ | 933,186    |   |  | $ | 1,705   |  
|                                                                                                         |  |                        |           |   |                  |   |        |                        |  |   |                  |   |  |                        |        |   |                  |   |            |   |  |   |         |  



Other Supplemental
InformationSelected Quarterly Data (unaudited) ($ in thousands):



|                                    |  |                    |             |              |   |                   |  |                  |             |  |   |            
|----------------------------------- |  | ------------------ | ----------- | ------------ | - | ----------------- |  | ---------------- | ----------- |  | - | -----------
|                                    |  | Three Months Ended
|                                    |  | March 31,2008      |             | June 30,2008 |   | September 30,2008 |  | December 31,2008
|Total Revenue and Other Income      |  | $                  | 160,613     |              | $ | 205,809           |  | $                | 216,947     |  | $ | 206,052    
|Total Costs and Expense             |  | $                  | 79,696      |              | $ | 101,423           |  | $                | 101,372     |  | $ | 114,201    
|Total Earnings Before Income Tax    |  | $                  | 80,917      |              | $ | 104,386           |  | $                | 115,575     |  | $ | 91,851     
|Net Income                          |  | $                  | 49,921      |              | $ | 64,255            |  | $                | 67,415      |  | $ | 57,482     
|Earnings per Share                  |  |                    |             |              |   |                   |  |                  |             |  |   |            
|Basic                               |  | $                  | 0.33        |              | $ | 0.43              |  | $                | 0.45        |  | $ | 0.38       
|                                    |  |                    |             |              |   |                   |  |                  |             |  |   |            
|Diluted                             |  | $                  | 0.33        |              | $ | 0.42              |  | $                | 0.45        |  | $ | 0.38       
|                                    |  |                    |             |              |   |                   |  |                  |             |  |   |            
|Weighted Average Shares Outstanding |  |                    |             |              |   |                   |  |                  |             |  |   |            
|Basic                               |  |                    | 150,923,490 |              |   | 150,937,820       |  |                  | 150,939,418 |  |   | 150,971,636
|                                    |  |                    |             |              |   |                   |  |                  |             |  |   |            
|Dilutive                            |  |                    | 151,324,786 |              |   | 151,438,737       |  |                  | 151,292,158 |  |   | 151,340,785
|                                    |  |                    |             |              |   |                   |  |                  |             |  |   |            



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CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)



|                                    |  |                    |             |              |   |                   |  |                   |             |  |   |            
|----------------------------------- |  | ------------------ | ----------- | ------------ | - | ----------------- |  | ----------------- | ----------- |  | - | -----------
|                                    |  | Three Months Ended
|                                    |  | March 31,2007      |             | June 30,2007 |   | September 30,2007 |  | December 31,2007*
|Total Revenue and Other Income      |  | $                  | 115,339     |              | $ | 133,667           |  | $                 | 110,732     |  | $ | 119,744    
|Total Costs and Expense             |  | $                  | 62,101      |              | $ | 66,735            |  | $                 | 58,735      |  | $ | 71,272     
|Total Earnings Before Income Tax    |  | $                  | 53,238      |              | $ | 66,932            |  | $                 | 51,997      |  | $ | 48,472     
|Net Income                          |  | $                  | 32,996      |              | $ | 41,488            |  | $                 | 31,296      |  | $ | 29,898     
|Earnings per Share                  |  |                    |             |              |   |                   |  |                   |             |  |   |            
|Basic                               |  | $                  | 0.22        |              | $ | 0.27              |  | $                 | 0.21        |  | $ | 0.20       
|                                    |  |                    |             |              |   |                   |  |                   |             |  |   |            
|Diluted                             |  | $                  | 0.22        |              | $ | 0.27              |  | $                 | 0.21        |  | $ | 0.20       
|                                    |  |                    |             |              |   |                   |  |                   |             |  |   |            
|Weighted Average Shares Outstanding |  |                    |             |              |   |                   |  |                   |             |  |   |            
|Basic                               |  |                    | 150,864,825 |              |   | 150,870,810       |  |                   | 150,895,233 |  |   | 150,914,225
|                                    |  |                    |             |              |   |                   |  |                   |             |  |   |            
|Dilutive                            |  |                    | 151,068,089 |              |   | 151,145,174       |  |                   | 151,149,432 |  |   | 151,241,316
|                                    |  |                    |             |              |   |                   |  |                   |             |  |   |            



|* | Included in the fourth quarter are out-of-period year-to-date adjustments made in the fourth quarter due to actualization and adjustments primarily related to sales with related
parties. These adjustments resulted in lower Revenue, Other Income, Total Earnings Before Income Tax, Net Income and Earnings per Share, both Basic and Diluted in the quarter ended December 31, 2007.
|- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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|Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
|------- | -------------------------------------------------------------------------------------



Changes in Accountants



On February 19, 2008 (Dismissal Date) CNX Gas dismissed PricewaterhouseCoopers LLP (PwC) as the Companys
independent registered public accounting firm. The audit Committee of the Board of Directors of the Company recommended and approved the dismissal of PwC.



The reports of PwC on the consolidated financial statements of the Company for the years ended December 31, 2007 and 2006, did not contain an adverse
opinion or a disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles.



During the years ended December 31, 2007 and 2006 and through the Dismissal Date, there were no disagreements with PwC on any matter of accounting
principles or practices, financial statement disclosures, or auditing scope or procedure, which disagreement(s), if not resolved to the satisfaction of PwC, would have caused it to make reference thereto in its reports on the financial statements of
the Company for such years. During the years ended December 31, 2007 and 2006, and through the Dismissal Date, there were no reportable events as defined under Item 304(a)(1)(v) of Regulation S-K.



Also, on February 19, 2008, the Audit Committee recommended and approved
the selection of Ernst & Young LLP (Ernst & Young), effective immediately, as the Companys new independent registered public accounting firm.



During the years ended December 31, 2007 and 2006, and through the Dismissal Date, neither the Company, nor anyone on its behalf,
consulted Ernst & Young regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered with respect to the financial
statements of the Company, and no written report was provided to the Company or oral advice was provided that Ernst & Young concluded was an important factor considered by the Company in reaching a decision as to the accounting, auditing or
financial reporting issue; or (ii) any matter that was the subject of a disagreement (as defined in Item 304(a)(1)(iv) of Regulation S-K and the related instructions) or a reportable event (as described in
Item 304(a)(1)(v) of Regulation S-K).



Disagreements with Accountants
on Accounting and Financial Disclosures



None.



|Item 9A. | Controls and Procedures
|-------- | -----------------------



Disclosure controls and procedures



CNX Gas, under the supervision and with the participation of its management, including the Companys principal executive officer and principal
financial officer, evaluated the effectiveness of its disclosure controls and procedures, as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the Exchange Act), as of the end of the period
covered by this annual report on Form 10-K. Based on that evaluation, our principal executive officer and principal financial officer have concluded that CNX Gas disclosure controls and procedures are effective to ensure that information
required to be disclosed by CNX Gas in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms, and include
controls and procedures designed to ensure that information required to be disclosed by us in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate
to allow timely decisions regarding required disclosure.



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Managements Annual Report on Internal Control Over Financial Reporting



CNX Gas management is responsible for establishing and maintaining adequate
internal control over financial reporting. CNX Gas 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.



CNX Gas internal control over financial reporting included policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and
dispositions of assets; (2) provide reasonable assurances that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures
are being made only in accordance with authorizations of management and the directors of CNX Gas; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CNX Gas
assets that could have a material effect on our financial statements.



Because of its inherent limitation, 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.



Management assessed the effectiveness of CNX Gas internal control over financial reporting as of December 31, 2008. In making this assessment,
management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on assessment and those criteria, management has concluded that CNX Gas maintained
effective internal control over financial reporting as of December 31, 2008. The effectiveness of CNX Gas internal control over financial reporting as of December 31, 2008 has been audited by Ernst and Young, LLP, an independent
registered public accounting firm, as stated in their report set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 8 of this Annual Report on Form 10-K.



Changes in Internal Controls Over Financial Reporting



There were no changes that occurred during the fourth quarter of the fiscal
year covered by the Annual Report on Form 10-K that have materially affected, or are reasonably likely to materially affect, the Companys internal control over financial reporting.



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Report of Independent Registered Public Accounting Firm



The Board of Directors and Stockholders of CNX Gas Corporation



We have audited CNX Gas Corporations internal control over financial
reporting as of December 31, 2008, based on criteria established in Internal ControlIntegrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CNX Gas Corporations
management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Managements Annual Report on
Internal Control Over Financial Reporting appearing under Item 9a. Our responsibility is to express an opinion on the companys internal control over financial reporting based on our audit.



We conducted our audit in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our
audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.



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
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.



In
our opinion, CNX Gas Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on the COSO criteria.



We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the
consolidated balance sheet of CNX Gas Corporation (and Subsidiaries) as of December 31, 2008, and the related consolidated statements of income, stockholders equity, and cash flows for the year then ended and our report dated
February 17, 2009 expressed an unqualified opinion thereon.



/s/ Ernst & Young LLP



Pittsburgh, PA

February 17, 2009



|Item 9B. | Other Information.
|-------- | ------------------



None.



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PART III



|Item 10. | Directors and Executive Officers of the Registrant.
|-------- | ---------------------------------------------------



Executive Officers of CNX Gas Corporation



The following is a list of CNX Gas executive officers, their ages as of February 15, 2009 and their positions and
offices held with CNX Gas.



|                     |  |     |  |                                                                   
|-------------------- |  | --- |  | ------------------------------------------------------------------
|Name                 |  | Age |  | Position                                                          
|J. Brett Harvey      |  | 58  |  | Chairman of the Board and Chief Executive Officer                 
|Nicholas J. DeIuliis |  | 40  |  | President and Chief Operating Officer                             
|William J. Lyons     |  | 60  |  | Executive Vice President and Chief Financial Officer              
|P. Jerome Richey     |  | 59  |  | Executive Vice President Corporate Affairs and Chief Legal Officer
|Robert P. King       |  | 56  |  | Executive Vice President Business Advancement and Support Services
|Robert F. Pusateri   |  | 58  |  | Executive Vice President Energy Sales and Transportation Services 



J. Brett Harveyhas been President and Chief Executive Officer and a Director of CONSOL Energy since January 1998. He has been a Director of CNX Gas Corporation since June 30, 2005 and he became Chairman of the Board and Chief Executive Officer of CNX Gas
Corporation on January 16, 2009. Mr. Harvey is a Director of Barrick Gold Corporation, the worlds largest gold producer, and Allegheny Technologies Incorporated, a specialty metals producer.



Nicholas J. DeIuliiswas a Director and President and Chief Executive
Officer of CNX Gas Corporation from June 30, 2005 to January 16, 2009, when he became President and Chief Operating Officer of CNX Gas Corporation and Executive Vice President and Chief Operating Officer of CONSOL Energy. From November
2004 until August 2005 he was the Senior Vice PresidentStrategic Planning of CONSOL Energy. Prior to that, Mr. DeIuliis served as Vice President Strategic Planning from April 2002 until November 2004, DirectorCorporate Strategy from
October 2001 until April 2002, ManagerStrategic Planning from January 2001 until October 2001 and SupervisorProcess Engineering from April 1999 until January 2001



William J. Lyonshas been Chief Financial Officer of CONSOL Energy since February 2001 and Chief Financial Officer of
CNX Gas Corporation since April 28, 2008. He added the title of Executive Vice President of CONSOL Energy on May 2, 2008 and of CNX Gas Corporation on January 16, 2009. From January 1995 until February 2001, Mr. Lyons held the
position of Vice PresidentController for CONSOL Energy. Mr. Lyons joined CONSOL Energy in 1976. He was a Director of CNX Gas Corporation from October 17, 2005 to January 16, 2009. Mr. Lyons is a director of Calgon Carbon
Corporation, a supplier of products and services for purifying water and air.



P. Jerome Richey became Executive Vice PresidentCorporate Affairs and Chief Legal Officer of CONSOL Energy and CNX Gas Corporation on January 16, 2009. He was General Counsel and Corporate Secretary
of CONSOL Energy since March 2005, and on June 20, 2007, he added the title of Senior Vice President. Prior to joining CONSOL Energy, Mr. Richey, for more than five years, was a shareholder in the Pittsburgh office for the law firm of
Buchanan Ingersoll & Rooney PC.



Robert P. Kingbecame Executive Vice PresidentBusiness Advancement and Support Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was Senior Vice PresidentAdministration since February 2, 2007 and he
served as Vice PresidentLand from August 2006 to February 2007. Prior to joining CONSOL Energy, Mr. King was Vice President of Interwest Mining Company (a subsidiary of PacifiCorp). Mr. King joined PacifiCorp in November 1990.



Robert F. Pusateri became Executive Vice President
Energy Sales and Transportation Services of CONSOL Energy and CNX Gas Corporation on January 16, 2009. Prior to that, he was named Vice President Sales of CONSOL Energy in 1996 and held that position until he was elected President of CONSOL
Energy Sales Company in August 2005. He first became an officer in May 1996.



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|Item 11. | Executive Compensation.
|-------- | -----------------------



The information required by this Item is incorporated by reference to the information under the captions General InformationCompensation of
Directors, General InformationUnderstanding our Director Compensation Table, Executive Compensation and Stock Option InformationCompensation Discussion and Analysis, Executive Compensation and Stock
Option InformationExecutive Compensation, Executive Compensation and Stock Option InformationBoard of Directors Report, General InformationThe Board of Directors and its CommitteesCompensation
Committee Interlocks and Insider Participation, and Potential Payments Upon Termination or Change-In-Control, in the Proxy Statement.



|Item 12. | Security Ownership of Certain Beneficial Owners and Management.
|-------- | ---------------------------------------------------------------



The information requested by this Item is incorporated by reference to the information under the captions Equity
Compensation Plan Information, and General InformationBeneficial Ownership of Securities in the Proxy Statement.



|Item 13. | Certain Relationships and Related Transactions.
|-------- | -----------------------------------------------



The information requested by this Item is incorporated by reference to the information under the captions Certain Relationships and Related
Transactions and General InformationThe Board of Directors and its Committees in the Proxy Statement.



|Item 14. | Principal Accounting Fees and Services.
|-------- | ---------------------------------------



The information required by this Item is incorporated by reference to the information in the table found in the section captioned Accountants and
Audit Committee and the information under the caption Accountants and Audit CommitteeAudit Committee Pre-Approval of Audit and Permissible Non-audit Services in the Proxy Statement.



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PART IV



|Item 15. | Exhibits and Financial Statement Schedules.
|-------- | -------------------------------------------



|               |  |                                                                                                                      
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------
|               | 
|(a)(1)         |  | Financial Statements:                                                                                                
|               | 
|               |  | The financial statements included in Part II, Item 8 above are filed as part of this annual report.                  
|               | 
|(a)(2)         |  | Financial Statement Schedules:  No schedules are required to be presented by CNX Gas.                                
|               | 
|(a)(3) and (b) |  | Exhibits:                                                                                                            
|               | 
|               |  | The exhibits listed on the Exhibit Index which follows the signatures hereto are filed as part of this annual report.



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SIGNATURES



Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 17th day of February 2009.



CNX GAS CORPORATIONBy:

/s/    J. BRETT HARVEYJ. Brett Harvey Chief Executive Officer




Pursuant to
the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 17th day of February 2009, by the following persons on behalf of the Registrant in the capacities indicated:



|                                                     |  |                                                                                                  
|---------------------------------------------------- |  | -------------------------------------------------------------------------------------------------
|Signature                                            |  | Title                                                                                            
|                                                     | 
|/s/    J. BRETT
HARVEY J. Brett Harvey               |  | Chairman and Chief Executive Officer (Chief Executive Officer and Director)                      
|                                                     | 
|/s/    WILLIAM J.
LYONS William J. Lyons             |  | Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
|                                                     | 
|/s/    PHILIP W.
BAXTER Philip W. Baxter             |  | Director                                                                                         
|                                                     | 
|/s/    JAMES E. ALTMEYER,
SR. James E. Altmeyer, Sr. |  | Director                                                                                         
|                                                     | 
|/s/    RAJ K.
GUPTA Raj K. Gupta                     |  | Director                                                                                         
|                                                     | 
|/s/    JOHN R.
PIPSKI John R. Pipski                 |  | Director                                                                                         



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EXHIBIT INDEX



|      |  |                                                                                                                                                                                                                          
|----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|3.1   |  | Amended and Restated Certificate of Incorporation of CNX Gas Corporation(1)                                                                                                                                              
|      | 
|3.2   |  | Second Amended and Restated Bylaws of CNX Gas Corporation, as amended(25)                                                                                                                                                
|      | 
|4.1   |  | Form of stock certificate(1)                                                                                                                                                                                             
|      | 
|10.1  |  | Summary of Employment Terms for Nicholas J. DeIuliis(2)*                                                                                                                                                                 
|      | 
|10.2  |  | Offer letter for Stephen W. Johnson(1)*                                                                                                                                                                                  
|      | 
|10.3  |  | Form of Change in Control Agreement for DeIuliis, Albert and Onifer(24)*                                                                                                                                                 
|      | 
|10.4  |  | Form of Change in Control Agreement for Johnson and Gibbons*                                                                                                                                                             
|      | 
|10.5  |  | Master Separation Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each of its subsidiaries (other than CNX Gas Corporation and its subsidiaries) and CNX Gas
Corporation and its subsidiaries(3)
|      | 
|10.6  |  | Master Cooperation and Safety Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each CEI Subsidiary (as defined therein) and CNX Gas Corporation and each CNX Subsidiary
(as defined therein)(3)  
|      | 
|10.7  |  | Amendment No. 1 to the Master Cooperation and Safety Agreement dated as of May 30, 2008(22)                                                                                                                              
|      | 
|10.8  |  | Tax Sharing Agreement dated August 1, 2005 between CONSOL Energy Inc. and CNX Gas Corporation(3)                                                                                                                         
|      | 
|10.9  |  | Services Agreement dated August 1, 2005 by and among CONSOL Energy Inc., CNX Land Resources Inc. and CNX Gas Corporation and its subsidiaries that become a party to the
agreement(3)                                    
|      | 
|10.10 |  | Intercompany Revolving Credit Agreement between CONSOL Energy Inc. and CNX Gas Corporation(3)                                                                                                                            
|      | 
|10.11 |  | Master Lease dated August 1, 2005 by and between CONSOL Energy Inc. and each of its subsidiaries made a party thereto and CNX Gas Company, LLC(3)                                                                        
|      | 
|10.12 |  | Credit Agreement dated October 7, 2005 between CNX Gas Corporation, certain of its subsidiaries and the Lender parties thereto(4)                                                                                        
|      | 
|10.13 |  | Indenture, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(5)                                                
|      | 
|10.14 |  | Supplemental Indenture No. 1, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(6)                             
|      | 
|10.15 |  | Supplemental Indenture No. 2, dated as of September 30, 2003, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as
trustee(7)                  
|      | 
|10.16 |  | Supplemental Indenture No. 3, dated as of April 15, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as
trustee(8)                      
|      | 
|10.17 |  | Supplemental Indenture No. 4, dated as of August 8, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as
trustee(3)                      
|      | 
|10.18 |  | Supplemental Indenture No. 5, dated as of October 21, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as
trustee(9)                    



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|      |  |                                                                                                                                                                                                  
|----- |  | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.19 |  | Precedent Agreement dated July 29, 2005 by and between East Tennessee Natural Gas, LLC and CNX Gas Company, LLC(10)                                                                              
|      | 
|10.20 |  | Firm Transportation Agreement, dated as of April 27th , 2006, between CNX Gas Company, LLC, a wholly owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC(11)                        
|      | 
|10.21 |  | Firm Lateral Transportation Agreement, dated as of April 27th, 2006, between CNX Gas Company, LLC, a wholly owned subsidiary of CNX Gas, and East Tennessee Natural Gas,
LLC(12)                 
|      | 
|10.22 |  | CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 and Form of Award Agreement thereunder(13)*                                
|      | 
|10.23 |  | CNX Gas Corporation Equity Incentive Plan, as amended*                                                                                                                                           
|      | 
|10.24 |  | Form of Award Agreements under CNX Gas Corporation Equity Incentive Plan, as amended(1)*                                                                                                         
|      | 
|10.25 |  | Offer letter of Mark D. Gibbons(14)*                                                                                                                                                             
|      | 
|10.26 |  | Summary description of CNX Gas 2007 Short-term incentive program(15)*                                                                                                                            
|      | 
|10.27 |  | Summary description of the base compensation and short-term incentive opportunities for the executive officers of CNX Gas for 2007(16)*                                                          
|      | 
|10.28 |  | Agreement of Sale entered into on June 8, 2007, by and between CNX Gas Company LLC, as purchaser, and Consolidation Coal Company, as seller(17)                                                  
|      | 
|10.29 |  | Asset Exchange Agreement entered into on June 20, 2007, but effective as of April 1, 2007, among American Land Holdings of Indiana, LLC, et al and CNX Gas Company
LLC(17)                       
|      | 
|10.30 |  | Form Oil and Gas Deed, Assignment, And Assumption, which is Exhibit F to Asset Exchange Agreement that is Exhibit 10.29, above(17)                                                               
|      | 
|10.31 |  | Asset Purchase Agreement entered into on June 20, 2007, but effective as of April 1, 2007, among American Land Holdings of Indiana, LLC, et al., as seller, and CNX Gas Company LLC,
as buyer(17)
|      | 
|10.32 |  | Form Oil and Gas Deed, Assignment, Assumption and Bill of Sale, which is Exhibit D to Asset Purchase Agreement that is Exhibit 10.31, above(17)                                                  
|      | 
|10.33 |  | Asset Purchase Agreement entered into on June 20, 2007, but effective as of April 1, 2007, among CNX Gas Company LLC, as seller, and Cyprus Creek Land Resources, LLC, as buyer(17)              
|      | 
|10.34 |  | Asset Purchase Agreement entered into on June 20, 2007, but effective as of April 1, 2007, among CNX Gas Company LLC, as seller, and Eastern Associated Coal, LLC, as
buyer(17)                  
|      | 
|10.35 |  | Offer letter to Dr. DeAnn Craig dated June 18, 2007(18)*                                                                                                                                         
|      | 
|10.36 |  | Schedule of Compensation of Non-Employee Directors, effective August 2007(18)*                                                                                                                   
|      | 
|10.37 |  | 2008 CNX Gas Long-Term Incentive Program and the Form of Award Agreement thereunder(19)*                                                                                                         
|      | 
|10.38 |  | Summary of CNX Gas 2008 Short-term Incentive Program(20)                                                                                                                                         
|      | 
|10.39 |  | CNX Gas Corporation Directors Deferred Fee Plan effective January 1, 2008(21)                                                                                                                    
|      | 
|10.40 |  | Separation Agreement and General Release dated as of April 30, 2008 between Mark D. Gibbons and CNX Gas Corporation(23)                                                                          
|      | 
|21    |  | Subsidiaries of CNX Gas Corporation                                                                                                                                                              
|      | 
|23.1  |  | Consent of Ernst & Young LLP                                                                                                                                                                     
|      | 
|23.2  |  | Consent of PricewaterhouseCoopers LLP                                                                                                                                                            
|      | 
|23.3  |  | Consent of Ralph E. Davis Associates, Inc.                                                                                                                                                       



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|     |  |                                                                                                                                                  
|---- |  | -------------------------------------------------------------------------------------------------------------------------------------------------
|23.4 |  | Consent of Schlumberger Data and Consulting Services                                                                                             
|     | 
|31.1 |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                               
|     | 
|31.2 |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                               
|     | 
|32.1 |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|     | 
|32.2 |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002



|(1) | Incorporated by reference from the Amendment No. 1 to the Registration Statement on Form S-1 (file no. 333-127483) filed on September 29, 2005
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------

|(2) | Incorporated by reference from the Current Report on Form 8-K filed by CONSOL Energy Inc. on August 19, 2005 (SEC File No. 001-14901)
|--- | -------------------------------------------------------------------------------------------------------------------------------------

|(3) | Incorporated by reference from the Current Report on Form 8-K filed by CONSOL Energy Inc. on August 12, 2005 (SEC File No. 001-14901)
|--- | -------------------------------------------------------------------------------------------------------------------------------------

|(4) | Incorporated by reference from the Current Report on Form 8-K filed by CONSOL Energy Inc. on October 13, 2005
|--- | -------------------------------------------------------------------------------------------------------------

|(5) | Incorporated by reference from Exhibit 4.1 to Form 10-K filed by CONSOL Energy Inc. on March 29, 2002
|--- | -----------------------------------------------------------------------------------------------------

|(6) | Incorporated by reference from Exhibit 4.2 to Form 10-K filed by CONSOL Energy Inc. on March 29, 2002
|--- | -----------------------------------------------------------------------------------------------------

|(7) | Incorporated by reference from Exhibit 4.2 to Form 10-Q filed by CONSOL Energy Inc. on November 19, 2003
|--- | --------------------------------------------------------------------------------------------------------

|(8) | Incorporated by reference from Exhibit 4.5 to Form 10-Q filed by CONSOL Energy Inc. on August 3, 2005
|--- | -----------------------------------------------------------------------------------------------------

|(9) | Incorporated by reference from the Amendment No. 2 to the Registration Statement on Form S-1 (file no. 333-127483) filed on October 27, 2005
|--- | --------------------------------------------------------------------------------------------------------------------------------------------

|(10) | Incorporated by reference from the Amendment No. 4 to the Registration Statement on Form S-1 (file no. 333-127483) filed on December 19, 2005
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------

|(11) | Incorporated by reference from Exhibit 10.1 to Form 10-Q filed by CNX Gas Corporation on August 2, 2006
|---- | -------------------------------------------------------------------------------------------------------

|(12) | Incorporated by reference from Exhibit 10.2 to Form 10-Q filed by CNX Gas Corporation on August 2, 2006
|---- | -------------------------------------------------------------------------------------------------------

|(13) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas Corporation on October 17, 2006 (SEC File No. 001-32723)
|---- | ---------------------------------------------------------------------------------------------------------------------------------------

|(14) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on January 26, 2007
|---- | --------------------------------------------------------------------------------------------------

|(15) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on March 1, 2007
|---- | -----------------------------------------------------------------------------------------------

|(16) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on April 27, 2007
|---- | ------------------------------------------------------------------------------------------------

|(17) | Incorporated by reference from the Form 10-Q filed by CNX Gas on July 31, 2007
|---- | ------------------------------------------------------------------------------

|(18) | Incorporated by reference from the Form 10-Q filed by CNX Gas on October 30, 2007
|---- | ---------------------------------------------------------------------------------

|(19) | Incorporated by reference from the Form 10-K filed by CNX Gas on February 15, 2008
|---- | ----------------------------------------------------------------------------------

|(20) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on April 25, 2008
|---- | ------------------------------------------------------------------------------------------------

|(21) | Incorporated by reference from the Form 10-Q filed by CNX Gas on April 30, 2008
|---- | -------------------------------------------------------------------------------

|(22) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on June 2, 2008
|---- | ----------------------------------------------------------------------------------------------

|(23) | Incorporated by reference from the Form 10-Q filed by CNX Gas on August 5, 2008
|---- | -------------------------------------------------------------------------------

|(24) | With respect to Messrs. Onifer and Albert, the change in control agreements have a two-times multiplier and do not contain a Section 280G gross up.
|---- | ---------------------------------------------------------------------------------------------------------------------------------------------------

|(25) | Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on January 20, 2009
|---- | --------------------------------------------------------------------------------------------------



In accordance with SEC Release 33-8238, Exhibits 32.1 and 32.2 are being furnished and not filed.

|* | Management compensatory contract or arrangement.
|- | ------------------------------------------------



111