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, 2009;

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.)

1000 CONSOL Energy Drive

Canonsburg, PA 15317-6506

(724) 485-4000

(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 whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    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, 2009, based on the closing price of the common stock on the New York Stock Exchange on such date ($26.27 per share), was $659,757,468. For purposes of determining this amount, affiliates include directors and executive officers, who, as of June 30, 2009, in the aggregate held 61,471 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 125,800,067 shares.

The number of shares outstanding of the registrant’s common stock as of January 29, 2010 is 150,986,918 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CNX Gas Corporation’s Proxy Statement for the Annual Meeting of Stockholders to be held on May 4, 2010, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business	5
Item 1A.	Risk Factors	19
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	30
Item 4.	Submission of Matters to a Vote of Security Holders	30
PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6.	Selected Financial Data	32
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 8.	Financial Statements and Supplementary Data	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	99
Item 9A.	Controls and Procedures	99
Item 9B.	Other Information	101
PART III
Item 10.	Directors and Executive Officers of the Registrant	102
Item 11.	Executive Compensation	103
Item 12.	Security Ownership of Certain Beneficial Owners and Management	103
Item 13.	Certain Relationships and Related Transactions	103
Item 14.	Principal Accounting Fees and Services	103
PART IV
Item 15.	Exhibits and Financial Statement Schedules	104
SIGNATURES		105

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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 continued weakness in global economic conditions, in any of the industries in which our customers operate, or sustained uncertainty in financial markets;

• 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;

• the replacement of our natural gas reserves;

• uncertainties in exploring for and producing gas;

• uncertainties in development projects in our operating areas and other unexplored areas;

• disruptions to, capacity constraints in or other limitations on the pipeline systems which deliver our gas;

• the availability of field services, equipment and personnel;

• a loss of our competitive position because of the competitive nature of the gas industry;

• acquisitions that we have made or may make in the future including the accuracy of our assessment of the acquired business or property;

• our ability to remove and dispose of water from the coal seams or other formations 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 effects of government regulation, permitting and other legal requirements;

• increased costs;

• the enactment of new or additional severance taxes in states where we operate;

• legal uncertainties regarding the ownership of the coalbed methane estate, and costs associated with perfecting title for gas rights in some of our properties;

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• our relationships and arrangements with CONSOL Energy;

• the effects of proposed legislation to regulate greenhouse gas emissions;

• our hedging activities may prevent us from benefiting from price increases and may expose us to other risks;

• litigation concerning real property rights, intellectual property rights, royalty calculations and other matters; and

• other factors discussed under “Risk Factors.”

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PART I

Item 1. Business

History of CNX Gas

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 also develop conventional Marcellus and other shale gas. 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, 2009, we had 1.9 trillion cubic feet equivalent of net proved reserves, with a PV-10 pre-tax value of $1.5 billion and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of $0.9 billion. Our proved reserves are approximately 86% CBM and 54% proved developed. We are one of the largest gas producers in the Appalachian Basin with net sales of 94.4 Bcf for the year ended December 31, 2009. Our proved reserves are long-lived with a reserve life index of 20.2 years.

We began extracting CBM in the early 1980s from coal seams in Virginia in order to reduce the gas content in the coal being mined by CONSOL Energy. We developed techniques to extract CBM from coal seams prior to mining in order to enhance the safety and efficiency of CONSOL Energy’s mining operations. Typically, the gas was vented to the atmosphere. In 1992, we began collecting and selling the extracted CBM. 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.

CNX Gas Corporation (CNX Gas) was formed on June 30, 2005. CONSOL Energy contributed its gas assets to CNX Gas effective August 8, 2005.

Our 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 corporate staff and management services as well as 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, 2009.

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Coordination with Mining Activities

Approximately 19% of our 2009 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.

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;

• Northern Appalachia, Mountaineer-Conventional, in northwest West Virginia and southwest Pennsylvania, where we continue development in the Marcellus Shale and shallow conventional zones;

• Northern Appalachia, Buckeye-Conventional in southeastern and central Ohio where we have begun drilling vertical exploration wells in the Marcellus and shallow conventional zones;

• 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; and

• 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 Huron 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.

CNX Gas has not filed reserve estimates with any federal agency.

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Central Appalachia

Virginia Operations CBM

We have the right to extract CBM in this region from approximately 405,000 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 coal 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 2009, frac wells account for approximately 76% 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. Approximately 10% of our 2009 Virginia gas production came from gob gas from active coal operations.

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. 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. In-mine horizontal wells accounted for approximately 1% of Virginia production in 2009.

Virginia Operations Shale and Tight Sands

We have 224,000 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 has 269,000 net acres of Chattanooga Shale. This largely contiguous acreage is composed of only a small number of

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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 799,000 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 nearly 8,000 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.

Nittany CBM

We have the right to extract CBM in this region of Pennsylvania from approximately 260,000 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 substantially increased our acreage position in the Marcellus Shale from 186,000 net acres at December 31, 2008 to 250,000 net acres at December 31, 2009. We also have 161,000 net acres of shallow conventional potential in Ohio, Pennsylvania, West Virginia, and New York. In 2009, CNX Gas drilled and completed fourteen wells in the Marcellus Shale in southwestern Pennsylvania. Three wells were completed as vertical completions and the remaining eleven wells were drilled and completed as horizontal wells. All wells were turned into production as of December 31, 2009.

Shallow Oil and Gas

In 2009, CNX Gas drilled and completed six shallow conventional wells and drilled one shallow conventional well to total depth in south central Pennsylvania. Two additional shallow conventional wells were drilled and completed in eastern Ohio. Eight of the nine total wells are in production at December 31, 2009 while the remaining well is awaiting completion of gathering facilities for collection.

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Others

Cardinal Shale

We control 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 2,500-4,000 feet. In 2009, we continued testing the New Albany Shale which will lead us to drilling two horizontal wells in early 2010. We also have identified shallow oil and gas in which we produce two additional wells.

Illinois Basin CBM

We also control 515,000 net CBM acres in Illinois and Indiana, including 71,000 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, 20,000 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.

Summary of Properties as of December 31, 2009

	Central Appalachia		Northern Appalachia		Other		Total
Estimated Net Proved Reserves (billion cubic feet equivalent)	1,551		332		28		1,911
Percent Developed	56	%	42	%	100	%	54	%
Net Producing Wells (including gob wells)	3,363		492		71		3,926
Net Proved Developed CBM Acres	148,988		92,533		—		241,521
Net Proved Undeveloped CBM Acres	34,433		12,209		—		46,642
Net Unproved CBM Acres(1)	548,904		1,046,088		674,162		2,269,154
Total Net CBM Acres	732,325		1,150,830		674,162		2,557,317
Net Proved Developed Oil & Gas Acres	8,129		5,005		98		13,232
Net Proved Undeveloped Oil & Gas Acres	5,936		1,720		—		7,656
Net Unproved Oil & Gas Acres(1)	483,202		248,094		399,040		1,130,336
Total Net Oil & Gas Acres	497,267		254,819		399,138		1,151,224

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

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Development Wells (Net)

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Gob wells and wells drilled by other operators that we participate in are excluded. There was one dry development well in 2009. There were no dry development wells in 2008 or 2007. As of December 31, 2009, six wells are still in process. The following table illustrates the wells drilled referenced above by geographic region:

	For the Year Ended December 31,
	2009	2008	2007
Central Appalachia	202	321	294
Northern Appalachia	45	213	76
Total	247	534	370

Exploratory Wells (Net)

During the year ended December 31, 2009, 2008 and 2007, we drilled in the aggregate 18, 56 and 9 net exploratory wells, respectively. As of December 31, 2009, ten wells are still in process. The following table illustrates the exploratory wells drilled referenced above by geographic region:

	As of December 31,
	2009			2008			2007
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	6	—	4	8	—	18	3	—	—
Northern Appalachia	5	1	2	6	—	20	—	—	—
Other	—	—	—	1	3	—	1	—	5
Total	11	1	6	15	3	38	4	—	5

Summary of Other Operating Data

Production

The following table sets forth net sales volumes produced for the periods indicated. There was no production from equity affiliates for the years ended December 31, 2009 and 2008. The year ended December 31, 2007 included our portion of equity interests.

	For the Year Ended December 31,
	2009	2008	2007
Total Produced (million cubic feet)	94,415	76,562	58,249

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Average Sales Prices and Lifting Costs

The following table sets forth the average sales price and the average lifting cost (the year ended December 31, 2007 includes 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 Year Ended December 31,
	2009		2008		2007
Average Gas Sales Price Before Effects of Financial Settlements (per thousand cubic feet)	$	4.15	$	8.99	$	6.87
Average Effects of Financial Settlements (per thousand cubic feet)	$	2.53	$	—	$	0.33
Average Gas Sales Price Including Effects of Financial Settlements (per thousand cubic feet)	$	6.68	$	8.99	$	7.20
Average Lifting Cost excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.48	$	0.58	$	0.39

Productive Wells and Acreage

Most of our development wells and proved 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, 2009, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:

	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage	260,327	254,753
Proved Undeveloped Acreage	56,090	54,298
Unproven Acreage	3,957,174	3,399,490
Total Acreage	4,273,591	3,708,541

(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 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 51.6 billion cubic feet of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per thousand cubic feet. As of December 31, 2009, we expect these transactions will cover approximately 45.7 billion cubic feet of our estimated 2010 production at an average price of $7.88 per thousand cubic feet, 22.6 billion cubic feet of our estimated 2011 production at an average price of $6.84 and 15.1 billion cubic feet of our estimated 2012 production at an average price of $6.84.

CNX Gas has purchased firm transportation capacity on various interstate pipelines to ensure gas production flows to market. As of December 31, 2009, CNX Gas has secured firm transportation capacity to cover more than our 2010, 2011 and 2012 hedged production.

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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 19 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 Securities and Exchange Commission (SEC).

	Net Reserves (Million cubic feet equivalent) as of December 31,
	2009		2008		2007
	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates	Consolidated Operations	Affiliates
Proved developed reserves	1,040,257	—	783,290	—	667,726	3,584
Proved undeveloped reserves	871,134	—	638,756	—	672,183	—
Total proved developed and undeveloped reserves	1,911,391	—	1,422,046	—	1,339,909	3,584

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,
	2009		2008		2007
Future net cash flows	$	2,391	$	2,824	$	3,609
Total PV-10 measure of pre-tax discounted future net cash flows(1)	$	1,480	$	2,004	$	2,288
Total standardized measure of after tax discounted future net cash flows	$	894	$	1,218	$	1,390

(1) We calculate our present value at 10% (PV-10) in accordance with the following table. Management believes that the presentation of the non-Generally Accepted Accounting Principle (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 of December 31,
	2009			2008			2007
	(Dollars in millions)
Future cash inflows	$	7,975		$	8,857		$	9,509
Future Production Costs		(3,123	)		(3,526	)		(3,005	)
Future Development Costs (including abandonments)		(996	)		(794	)		(636	)
Future net cash flows (pre-tax)		3,856			4,537			5,868
10% discount factor		(2,376	)		(2,533	)		(3,580	)
PV-10 (Non-GAAP measure)		1,480			2,004			2,288
Undiscounted Income Taxes		(1,465	)		(1,714	)		(2,259	)
10% discount factor		879			928			1,361
Discounted Income Taxes		(586	)		(786	)		(898	)
Standardized GAAP measure	$	894		$	1,218		$	1,390

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, 2009, CNX Gas had 174 employees. The number of employees has been significantly reduced from the prior year as a result of the management consolidation with CONSOL Energy which took place on January 16, 2009. None of our employees are represented by a union.

Available Information

CNX Gas maintains a website on the World Wide Web at www.cnxgas.com. CNX Gas makes available, free of charge, on this website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) of the Securities Exchange Act of 1934, as amended (the “1934 Act”), as soon as reasonably practicable after such reports are available, electronically filed with, or furnished to the Securities and Exchange Commission (SEC). These reports are also available at the SEC’s website at www.sec.gov.

Laws and 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;

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• 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.

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 years ended 2009, 2008 and 2007. 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 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.

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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;

• the Emergency Planning and Community Right-to-Know Act; and

• 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 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

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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 have been 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 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, 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 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 they 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.

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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.

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 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.

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West Virginia

The West Virginia 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, 2009, 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.

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

Investment in our securities is subject to various risks, including risks and uncertainties inherent in our business. The following sets forth factors related to our business, operations, financial position or future financial performance or cash flows which could cause an investment in our securities to decline and result in a loss.

GENERAL RISK FACTORS

Continued weakness in global economic condition or, in any of the industries in which our customers operate, or sustained uncertainty in financial markets may have material adverse impacts on our business and financial condition that we currently cannot predict.

Economic conditions in the United States and globally have deteriorated and the extent and timing of a full recovery, especially in the United States and Europe, is uncertain. Financial markets in the United States, Europe and Asia have also experienced 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 in the United States and Europe. Although we cannot predict the impacts, continued weakness in the United States or global economies could materially adversely affect our business and financial condition. For example:

• the demand for natural gas in the United States has declined and may remain at low levels or further decline if economic conditions remain weak and continue to 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; and

• 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;

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• technological advances affecting energy consumption;

• domestic and foreign governmental regulations;

• proximity and capacity of gas pipelines and other transportation facilities; and

• the price and availability of alternative fuels.

Many of these factors may be beyond our control. 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 and/or our ability to borrow, 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 reserves 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. 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 historical 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 thousand cubic feet, then the pre-tax present value using a 10% discount rate of our proved reserves as of December 31, 2009 would decrease from $1.5 billion to $1.4 billion. The standardized Generally Accepted Accounting Principle measure associated with this decline of $0.10 per thousand cubic feet, would be approximately $0.8 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, 2009, 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.

Our focus on new development projects in our operating areas and other unexplored areas increases the risks inherent in our gas and oil activities.

We have little or no proved reserves in 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 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

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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 shale gas drilling and production operations require adequate sources of water to facilitate the fracturing process and the disposal of that water when it flows back to the well-bore, and our CBM gas drilling and production operations require the removal and disposal of water from the coal seams, from which we produce gas. If we 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.

New environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may 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.

Coal seams, frequently contain water that must be removed in order for the gas to detach from the coal and flow to the wellbore. Further, we must remove the water that we use to fracture our shale gas wells when it flows back to the well-bore. Our ability to remove and dispose of water will affect our production and the cost of water treatment and disposal may affect our profitability. The imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct hydraulic fracturing or disposal of waste, including, produced water, drilling fluids and other wastes associated with the exploration, development and production of natural gas.

Coalbed methane and other gas that we produce often contains 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 saleable 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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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.

Enactment of a severance tax in several states where we have operations, including Pennsylvania, on natural gas could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities in those states.

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 thousand 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 2009, 17%, or 18.4 billion cubic feet, of our production was from Pennsylvania. In addition, a significant amount of our Marcellus shale play acreage is in Pennsylvania. We cannot predict whether Pennsylvania (or any other states) will adopt any such tax, nor if adopted the rate of tax. If states adopt such taxes, it could adversely impact our results of existing operations and the economic viability of exploiting new gas drilling and production opportunities.

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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 requires 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 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.

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 (GHG) 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 GHG emissions and we may get credit for those reductions. We have voluntarily reported those reductions of GHG 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 GHG reduction benefits of our production activities both prior to and subsequent to the 2005 separation.

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The U.S. Congress is considering climate change legislation that proposes to restrict GHG emissions. President Obama has pledged to implement an economy-wide cap-and-trade program to reduce GHG emissions 80 percent by 2050 and pledged that he would cause the United States to be a world leader on GHG reduction and re-engage with the United Nations Framework Convention on Climate Change to develop a global GHG program. In 2007, the U.S. Supreme Court held in Massachusetts v. Environmental Protection Agency (EPA), that the EPA had authority to regulate GHGs under the Clean Air Act and a number of states have filed lawsuits seeking to force the EPA to adopt GHG regulations. In December 2009, EPA made a determination that GHGs cause or contribute to air pollution and may reasonably be anticipated to endanger public health or welfare, which findings are prerequisites to EPA regulating GHGs under the Clean Air Act. 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 GHG 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, 2009, we had hedges on approximately 45.7 billion cubic feet of our 2010 natural gas production, 22.6 billion cubic feet of our 2011 natural gas production and 15.1 billion cubic feet of our 2012 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 earnings. This may result in more volatility in our income in future periods.

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

At December 31, 2009, we had $57.9 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;

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• 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, all of our executive officers are executive officers of CONSOL Energy and all but one of our directors also serve on their board of directors 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.

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.

Executive officers of CONSOL Energy serve as our executive officers. In addition, all but one 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 of 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.

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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 2009, approximately 19% of our gas production was produced in connection with coal extraction by CONSOL Energy; 7% of our production was associated with CONSOL Energy’s active mining operations.

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;

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• 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 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 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.

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

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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 1000 CONSOL Energy Drive, Canonsburg, PA 15317-6506. Our other properties are described under “Gas Operations—Areas of Operation” in Item 1.

Item 3. Legal Proceedings

The first through sixth paragraphs of Note 20—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 2009 and 2008 quarters ended:

	2009				2008
	High		Low		High		Low
March 31	$	29.30	$	20.00	$	39.53	$	26.66
June 30	$	32.46	$	22.99	$	45.51	$	31.82
September 30	$	32.19	$	23.62	$	42.07	$	19.77
December 31	$	36.00	$	26.47	$	31.75	$	14.08

As of December 31, 2009 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, 2009.

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Company / Index	Base Period Jan-19-06	Indexed Returns Six Months Ending
		Jun-06	Dec-06	Jun-07	Dec-07	Jun-08	Dec-08	Jun-09	Dec-09
CNX Gas Corporation	100	133.33	113.33	136.00	142.00	186.84	121.33	116.76	131.20
S&P MidCap 400 Index	100	99.69	105.50	118.14	113.92	109.48	72.65	78.80	99.81
S&P Oil & Gas Exploration & Production	100	96.26	95.85	115.70	138.43	186.29	90.59	96.35	128.73

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 Gas 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.

See Part III, Item 11, Executive Compensation for information relating to CNX Gas equity compensation plans.

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, 2009, 2008, 2007, 2006 and 2005 are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2009, 2008, 2007, 2006 and 2005 and the related consolidated statements of income and cash flows for each of the years ended December 31, 2009, 2008, 2007, 2006 and 2005, 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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STATEMENTS OF INCOME DATA

(Dollars in thousands, except per share data)

	For the Year Ended December 31,
	2009			2008		2007		2006		2005
	(In thousands)
RESULTS OF OPERATIONS
Outside Sales	$	627,419		$	678,793	$	404,835	$	385,056	$	277,031
Related Party Sales		3,179			9,532		11,618		8,490		6,052
Royalty Interest Gas Sales		40,951			79,302		46,586		51,054		45,351
Purchased Gas Sales		7,040			8,464		7,628		43,973		275,148
Other Income		4,855			13,330		8,815		26,264		9,710
TOTAL REVENUE AND OTHER INCOME		683,444			789,421		479,482		514,837		613,292
Lifting Costs		55,285			67,653		38,721		33,357		30,399
Gathering and Compression Costs		95,687			83,752		61,798		58,102		43,903
Royalty Interest Gas Costs		32,423			74,041		40,011		41,998		36,641
Purchased Gas Costs		6,442			8,175		7,162		44,843		278,720
Exploration and Other Costs		17,201			4,995		1,759		2,060		2,729
General and Administrative		66,655			59,244		42,664		30,155		16,824
Other Corporate Expenses		32,871			21,002		12,161		9,013		2,305
Depreciation, Depletion and Amortization		107,251			70,010		48,961		37,999		35,039
Interest Expense		7,568			7,820		5,606		870		14
TOTAL COSTS AND EXPENSES		421,383			396,692		258,843		258,397		446,574
Earnings Before Income Taxes and Noncontrolling Interest		262,061			392,729		220,639		256,440		166,718
Noncontrolling Interest		(1,037	)		—		—		—		—
Earnings Before Income Taxes		263,098			392,729		220,639		256,440		166,718
Income Taxes		98,636			153,656		84,961		96,573		64,550
NET INCOME	$	164,462		$	239,073	$	135,678	$	159,867	$	102,168
Earnings Per Share from Net Income:
Basic	$	1.09		$	1.58	$	0.90	$	1.06	$	0.76
Diluted	$	1.09		$	1.58	$	0.90	$	1.06	$	0.76
Weighted Average Number of Common Shares Outstanding:
Basic		150,977,235			150,947,516		150,886,433		150,845,518		134,071,334
Dilutive		151,325,146			151,331,953		151,133,520		151,017,456		134,137,219

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BALANCE SHEETS DATA

(In thousands)

	As of December 31,
	2009			2008			2007		2006		2005
Working Capital (Deficiency) (Unaudited)	$	(68,630	)	$	(31,192	)	$	25,303	$	115,824	$	3,720
Total Assets		2,171,382			2,124,973			1,380,703		1,155,001		859,167
Long Term Debt (Including current portion)		74,306			83,144			72,768		66,470		—
Total Deferred Credits and Other Liabilities		381,548			384,367			227,833		153,977		109,226
Total Stockholders’ Equity		1,506,900			1,384,874			1,023,237		880,215		679,472

CASH FLOW STATEMENTS DATA

(In thousands)

	For the Year Ended December 31,
	2009			2008			2007			2006			2005
Net Cash Provided by Operating Activities	$	360,163		$	447,375		$	272,448		$	243,569		$	144,997
Net Cash Used in Investing Activities		(334,909	)		(559,132	)		(354,227	)		(156,020	)		(108,287	)
Net Cash Provided by (Used in) Financing Activities		(26,056	)		81,635			6,654			(449	)		(16,640	)

OTHER OPERATING DATA

(Unaudited)

	For the Year Ended December 31,
	2009		2008		2007		2006		2005
Net Sales Volumes (Bcf)(1)		94.4		76.6		58.3		56.1		48.4
Average Sales Price Including Effects of Financial Settlements ($ per Mcf)(1)(2)	$	6.68	$	8.99	$	7.20	$	7.04	$	5.90
Total Average Costs ($ Per Mcf)(1)	$	3.44	$	3.66	$	3.34	$	2.86	$	2.67
Net Estimated Proved Reserves (Bcfe)(1)(3)		1,911		1,422		1,343		1,265		1,130

OTHER FINANCIAL DATA

(In thousands)

	For the Year Ended December 31,
	2009		2008		2007		2006		2005
Capital Expenditures(4)	$	336,447	$	560,663	$	357,199	$	154,243	$	110,752
EBIT(5) (Unaudited)		270,602		400,149		222,452		253,857		166,314
EBITDA(5) (Unaudited)		377,853		470,159		271,413		291,856		201,353

(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 years ended December 31, 2009 and 2008. Knox Energy is included in the equity earnings data in 2007, 2006 and 2005. 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.

(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 our portion of equity affiliates. Equity affiliates portion of reserves included were 3.6 Bcfe at December 31, 2007, 2.2 at December 31, 2006 and 2.7 at December 31, 2005. There were no equity in affiliates at December 31, 2009 and 2008.

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(4) Capital expenditures for 2008 include the acquisition of the remaining interest in Knox Energy which CNX Gas did not previously own, and other acquisition transactions. Capital expenditures in 2007 include those related to the 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 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 Year Ended December 31,
(In thousands)	2009		2008		2007		2006		2005
Net Income	$	164,462	$	239,073	$	135,678	$	159,867	$	102,168
Add: Interest Expense		7,568		7,820		5,606		870		14
Less: Interest Income		64		400		3,793		3,453		418
Add: Income Tax Expense		98,636		153,656		84,961		96,573		64,550
Earnings Before Net Interest and Taxes (EBIT)		270,602		400,149		222,452		253,857		166,314
Add: Depreciation, Depletion and Amortization		107,251		70,010		48,961		37,999		35,039
Earnings Before Net Interest, Taxes and Depreciation, Depletion and Amortization (EBITDA)	$	377,853	$	470,159	$	271,413	$	291,856	$	201,353

35

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The U.S. economy began growing in the third quarter of 2009 and continued growing in the fourth quarter. Due to the significant fiscal spending and relaxed monetary policy in the United States, a modest recovery appears likely to continue in the U.S. through 2010. This should lead to an increase in demand for energy products from industrial customers, power generators and steel producers. Depending on the pace and sustainability of the recovery, we believe substantial opportunities exist for our gas business.

At the onset of the winter heating season, natural gas in storage fields was at record high levels. Because of much colder than normal weather in much of the U.S. from mid-December through mid-January, gas in storage has been drawn down to normal levels. The economic recovery is expected to positively affect industrial and commercial demand.

During the year ended December 31, 2009, we achieved the following:

• Completed another year with no employee-related lost time accidents. We have accumulated over 4.1 million man hours without a lost time accident;

• Drilled a record 201 vertical frac wells in our Virginia Operations;

• Drilled, completed, and brought online fourteen wells in the Marcellus Shale;

• Successfully increased our acreage with Marcellus Shale potential by 64,000 acres, to a December 31, 2009 total of 250,000 acres. Of this, approximately 170,000 acres is considered to be Tier 1. The company remains committed to expanding its footprint to 400,000 acres;

• Grew production by 23% in 2009 while paying down a portion of outstanding debt; and

• Grew our proved reserves in 2009 by one-half trillion cubic feet (Tcf), or 34%, to 1.9 Tcf.

In 2008, we verified and registered for trading on the Chicago Climate Exchange (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 currently 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. No additional emission offsets were verified or registered in 2009.

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

36

Year Ended December 31, 2009 compared with Year Ended December 31, 2008

(Amounts reported in millions)

Net Income

Net income attributable to CNX Gas Shareholders changed primarily due to the following items:

	2009			2008		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	627		$	679	$	(52	)	(7.7	)%
Related Party Sales		3			10		(7	)	(70.0	)%
Royalty Interest Gas Sales		41			79		(38	)	(48.1	)%
Purchased Gas Sales		7			8		(1	)	(12.5	)%
Other Income		5			13		(8	)	(61.5	)%
Total Revenue and Other Income		683			789		(106	)	(13.4	)%
Costs and Expenses:
Lifting Costs		55			68		(13	)	(19.1	)%
Gathering and Compression Costs		96			84		12		14.3	%
Royalty Interest Gas Costs		32			74		(42	)	(56.8	)%
Purchased Gas Costs		6			8		(2	)	(25.0	)%
Exploration and Other Costs		17			4		13		325.0	%
General and Administrative		67			59		8		13.6	%
Other Corporate Expenses		33			21		12		57.1	%
Depreciation, Depletion and Amortization		107			70		37		52.9	%
Interest Expense		8			8		—		—
Total Costs and Expenses		421			396		25		6.3	%
Earnings Before Income Taxes and Noncontrolling Interest		262			393		(131	)	(33.3	)%
Noncontrolling Interest		(1	)		—		(1	)	100.0	%
Earnings Before Income Taxes		263			393		(130	)	(33.1	)%
Income Tax Expense		99			154		(55	)	(35.7	)%
Net Income Attributable to CNX Gas Shareholders	$	164		$	239	$	(75	)	(31.4	)%

Lower net income attributable to CNX Gas Shareholders was primarily due to lower sales prices, offset, in part, by higher sales volumes and lower unit costs. See below for additional details.

Revenue and Other Income

Revenue and other income decreased due to the following items:

	2009		2008		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	627	$	679	$	(52	)	(7.7	)%
Related Party Sales		3		10		(7	)	(70.0	)%
Royalty Interest Gas Sales		41		79		(38	)	(48.1	)%
Purchased Gas Sales		7		8		(1	)	(12.5	)%
Other		5		13		(8	)	(61.5	)%
Total Revenue and Other Income	$	683	$	789	$	(106	)	(13.4	)%

37

Outside sales and related party sales, combined, decreased primarily due to lower average sales prices received, offset, in part, by higher volumes of gas sold.

	2009		2008		Variance			Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		94.4		76.6		17.8		23.2	%
Average Sales Price Per thousand cubic feet	$	6.68	$	8.99	$	(2.31	)	(25.7	)%

Sales volumes increased as a result of additional wells coming online from our on-going drilling program. The decrease in average sales price is the result of the general market price decreases in the year-to-year comparison. The general market price decline was offset, in part, by the various gas swap transactions entered into by CNX Gas. These gas swap transactions qualify as financial cash flow hedges that exist parallel to the underlying physical transactions. These financial hedges represented approximately 51.6 Bcf of our produced gas sales volumes for the year ended December 31, 2009 at an average price of $8.76 per Mcf. In the year ended December 31, 2008, these financial hedges represented approximately 43.4 Bcf at an average price of $9.25 per Mcf.

Royalty interest gas sales represent the revenues for the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease 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.

	2009		2008		Variance			Percentage Change
Royalty Interest Gas Sales Volumes (in billion cubic feet)		9.8		8.5		1.3		15.3	%
Average Sales Price Per thousand cubic feet	$	4.17	$	9.32	$	(5.15	)	(55.3	)%

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

	2009		2008		Variance			Percentage Change
Purchased Gas Sales Volumes (in billion cubic feet)		1.6		1.0		0.6		60.0	%
Average Sales Price Per thousand cubic feet	$	4.46	$	8.76	$	(4.30	)	(49.1	)%

Other revenue decreased $8 million due to the 2008 receipt of proceeds from our insurance carrier as final settlement of the insurance claim related to the July 2007 Buchanan Mine event which idled the mine. The $8 million represented business interruption coverage.

Costs and Expenses

Costs and Expenses increased due to the following items:

	2009		2008		Dollar Variance			Percentage Change
Costs and Expenses:
Lifting Costs	$	55	$	68	$	(13	)	(19.1	)%
Gathering and Compression		96		84		12		14.3	%
Royalty Interest Gas Costs		32		74		(42	)	(56.8	)%
Purchased Gas Costs		6		8		(2	)	(25.0	)%
Exploration and Other Costs		17		4		13		325.0	%
General and Administrative		67		59		8		13.6	%
Other Corporate Expenses		33		21		12		57.1	%
Depreciation, Depletion and Amortization		107		70		37		52.9	%
Interest Expense		8		8		—		—
Total Costs and Expenses	$	421	$	396	$	25		6.3	%

38

Lifting costs decreased $13 million in the year-to-year comparison due to lower average unit costs, offset, in part, by higher sales volumes.

	2009		2008		Variance			Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		94.4		76.6		17.8		23.2	%
Average Lifting Costs per thousand cubic feet	$	0.58	$	0.89	$	(0.31	)	(34.8	)%

Average lifting costs per unit decreased in 2009 as a result of several factors.

• Severance taxes have decreased $0.20 per thousand cubic feet primarily due to the reduction in average sales prices in the year ended December 31, 2009. The severance tax decrease also includes a reduction of $0.05 per thousand cubic feet attributable to a revised estimate of a pending litigation settlement.

• Well service costs have also decreased by $0.07 per thousand cubic feet due to lower contract service rig hours needed as a result of less pump maintenance being required in the year ended December 31, 2009.

• Other costs have decreased $0.14 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during 2009. Dollars spent remained consistent in the year-to-year comparisons, therefore additional volumes decreased the unit costs.

These decreases in unit costs were offset, in part, by a $0.10 per thousand cubic feet increase related to idling various drilling rigs throughout the company. Some of CNX Gas’ drilling contracts require minimum payments be made to the contracting party when drilling rigs are not being used. The CNX Gas drilling program has been slowed down pending a change in the economic environment. These charges resulted in an increase to costs.

The increase of $12 million in gathering and compression costs was attributable to higher volumes produced during the year ended December 31, 2009 compared to the year ended December 31, 2008, offset, in part, by lower average unit costs.

	2009		2008		Variance			Percentage Change
Produced Gas Sales Volumes (in billion cubic feet)		94.4		76.6		17.8		23.2	%
Average Gathering and Compression Costs per thousand cubic feet	$	1.01	$	1.09	$	(0.08	)	(7.3	)%

Average gathering and compression unit costs were $0.08 per thousand cubic feet lower in the period-to-period comparison. Improvements in the average unit costs were attributable to the following:

• Gob collection charges were $0.04 per thousand cubic feet lower. Lower gob collection charges per unit were primarily due to the Buchanan longwall being idled throughout some of 2009.

• Compression expenses decreased $0.03 per thousand cubic feet primarily due to a reduction in the number of compressors utilized in the Northern Appalachian production field. Due to the slow-down in the drilling program in Northern Appalachia, rented compressors have been returned to more appropriately design the gathering fields for existing needs.

• Other costs have decreased $0.13 per thousand cubic feet primarily due to the impact of additional volumes of gas sold during 2009. Dollars spent remained consistent in the year-to-year comparison, therefore additional volumes decreased the unit cost.

These decreases in unit costs were offset by the following:

• Firm transportation costs increased $0.08 per thousand cubic feet primarily due to acquiring additional capacity in the Northern Appalachian region after December 31, 2008.

39

• Power and fuel costs increased $0.04 per thousand cubic feet due to a power rate increase which occurred after December 31, 2008. Also, the increase was due to additional compressors being placed in service after December 31, 2008 along the existing gathering system in the Central Appalachian production field in order to flow the increasing gas volumes more efficiently.

Royalty interest gas sales represent the revenues for the portion of production belonging to royalty interest owners sold by CNX Gas on their behalf. The decrease 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.

	2009		2008		Variance			Percentage Change
Gas Royalty Interest Sales Volumes (in billion cubic feet)		9.8		8.5		1.3		15.3	%
Average Cost Per thousand cubic feet	$	3.30	$	8.70	$	(5.40	)	(62.1	)%

Purchased gas volumes represent volumes of gas purchased from third-party producers that we sell. Purchased gas volumes sold also reflect the impact of pipeline imbalances. The lower average cost per thousand cubic feet is due to overall price decreases and contractual differences among customers in the year-to-year comparison.

	2009		2008		Variance			Percentage Change
Purchased Gas Cost Volumes (in billion cubic feet)		1.7		1.0		0.7		70.0	%
Average Cost Per thousand cubic feet	$	3.75	$	8.13	$	(4.38	)	(53.9	)%

Exploration and Other Costs increased $13 million due to the following items:

	2009		2008		Dollar Variance		Percentage Change
Dry hole and other costs	$	9	$	1	$	8	800.0	%
Exploration		8		3		5	166.7	%
Total Exploration and Other Costs	$	17	$	4	$	13	325.0	%

Dry hole and other costs were incurred related to the determination that certain areas where an exploration well was drilled would not be economical to pursue. The costs for the exploration wells, which were previously capitalized, were expensed. In 2009, other costs include costs which were previously capitalized related to a lease. The lease was surrendered due to the properties being widely scattered and not adjacent to any of our existing operating units. Also, costs related to particular permits where management has determined that no drilling will take place have been expensed.

Exploration expense increased primarily due to additional land rental expenses and higher geological and geophysical charges in the year-to-year comparison.

General and administrative expenses increased $8 million in the year-to-year comparison. The increased general and administrative expense is attributable to the reassignment of certain CNX Gas personnel in the fourth quarter of 2008 from operational roles to general and administrative oversight functions.

Other corporate expenses have increased $12 million due to the following items:

	2009		2008		Dollar Variance			Percentage Change
Stock-based compensation	$	11	$	12	$	(1	)	(8.3	)%
Short-term incentive compensation		16		8		8		100.0	%
Contract settlement		3		—		3		100.0	%
Miscellaneous		3		1		2		200.0	%
Total Other Corporate Expenses	$	33	$	21	$	12		57.1	%

40

Stock-based compensation expense decreased $1 million in the year-to-year comparison. The improvement was related to the CNX Gas long-term incentive compensation plan being converted to CONSOL Energy restricted stock units in 2009. The year ended December 31, 2009 contains $3 million of fair value adjustments associated with the exchange offer to convert CNX Gas performance share units into CONSOL Energy restricted stock units.

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 goals. Approximately $12 million of short-term incentive compensation was allocated from CONSOL Energy. The allocation is attributable to the April 2009 management consolidation which resulted in employees being transferred from CNX Gas to CONSOL Energy. The CONSOL Energy employees provide substantially all of the management and administrative functions of CNX Gas, therefore a representative portion of CONSOL Energy’s short-term incentive compensation is now allocated to CNX Gas. This increase was offset, in part, by lower short-term incentive compensation due to fewer CNX Gas employees.

The year ended December 31, 2009 includes $3 million related to a contract buyout with a driller in order to mitigate idle rig charges in certain areas where drilling is not expected to ramp up in the near term.

Miscellaneous other corporate expenses increased $2 million in the year-to-year comparison primarily due to cease use expenses incurred related to the relocation of CNX Gas’ corporate office and various other transactions that occurred throughout both years, none of which were individually material.

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

	2009		2008		Dollar Variance		Percentage Change
Production	$	86	$	51	$	35	68.6	%
Gathering		21		19		2	10.5	%
Total Depreciation, Depletion and Amortization	$	107	$	70	$	37	52.9	%

The increase in production related depreciation, depletion and amortization was primarily due to increased volumes produced, combined with an increase in the units of production rates for the Northern Appalachian region 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. Production asset depreciation also increased due to the recalculation of rates in 2009 related to the Marcellus Shale wells and other various assets being placed in service after December 31, 2008.

Gathering depreciation, depletion and amortization is recorded using the straight-line method and increased $2 million in 2009 due to assets placed in service after December 31, 2008.

Interest expense remained consistent at $8 million in the year-to-year comparison.

Noncontrolling Interests

Noncontrolling interests represents the portion of earnings from a variable interest entity that is fully consolidated because CNX Gas is the primary beneficiary. CNX Gas owns no portion of the variable interest entity and therefore the noncontrolling interest reverses all earnings impact on consolidation.

41

Income Taxes

	2009			2008			Variance			Percentage Change
Earnings Before Income Taxes	$	263		$	393		$	(130	)	(33.1	)%
Income Tax Expense	$	99		$	154		$	(55	)	(35.7	)%
Effective Income Tax Rate		37.5	%		39.1	%		(1.6	)%

CNX Gas’ effective income tax rate decreased in the year-to-year comparison primarily due to changes in the net effect of the domestic production activities deductions. See Note 5—Income Taxes of the Consolidated Financial Statements for additional details.

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		Dollar Variance			Percentage Change
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	%
Exploration and Other		4		1		3		300.0	%
General and Administrative		59		43		16		37.2	%
Other Corporate Expenses		21		12		9		75.0	%
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 Attributable to CNX Gas Shareholders	$	239	$	136	$	103		75.7	%

42

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		Dollar Variance			Percentage Change
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		Percentage Change
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	%

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		Percentage Change
Royalty Interest Gas 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	%

Royalty interest gas sales represent the revenues for 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			Percentage Change
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.

43

Other income consists of the following items:

	2008		2007		Dollar Variance			Percentage Change
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.

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		Dollar Variance		Percentage Change
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	%
Exploration and Other Costs		4		1		3	300.0	%
General and Administrative		59		43		16	37.2	%
Other Corporate Expenses		21		12		9	75.0	%
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	%

44

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

	2008		2007		Variance		Percentage Change
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 2008 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		Percentage Change
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	%

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	%

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Royalty interest gas costs represent the expenses for 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			Percentage Change
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.

Exploration and Other Costs increased $3 million primarily due to 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		Dollar Variance		Percentage Change
Wages, salaries and related expenses	$	28	$	18	$	10	55.6	%
Professional services		19		15		4	26.7	%
Other		12		10		2	20.0	%
Total General and Administrative	$	59	$	43	$	16	37.2	%

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.

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

Other corporate expenses have increased $9 million due to the following items:

	2008		2007		Dollar Variance		Percentage Change
Stock-based compensation	$	12	$	5	$	7	140.0	%
Short-term incentive compensation		8		6		2	33.3	%
Miscellaneous		1		1		—	—
Total Other Corporate Expenses	$	21	$	12	$	9	75.0	%

Stock-based compensation 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.

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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.

Miscellaneous Other Corporate Expenses remained consistent in the year-to-year comparison.

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

	2008		2007		Dollar Variance		Percentage Change
Production	$	51	$	32	$	19	59.4	%
Gathering		19		17		2	11.8	%
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.

Interest expense increased due to the following items:

	2008		2007		Dollar Variance		Percentage Change
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.

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			Percentage Change
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.

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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. 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 in 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

As of December 31, 2009, we have two types of share based payment awards outstanding: options and restricted 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,

• 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 CNX Gas 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 on the date of the grant.

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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

Proved oil and gas reserves are defined by the Securities and Exchange Commission (SEC) 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.

Our estimation of net recoverable reserves is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. Our reserves are audited by a third party. Our estimates of proved natural gas reserves and future net revenues 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.

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

Our deferred tax assets and liabilities are recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. Our deferred tax assets may 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, 2009, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $369.4 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.

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Gas Well Closing

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. An asset retirement obligation is recognized at fair value 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. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion on the asset retirement obligation 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, including borrowings and letters of credit, which expires in October 2010. CNX Gas can request an additional $100 million increase in the aggregate outstanding principal amount. The agreement contains a negative pledge provision, pursuant to which CNX Gas assets cannot be used to secure other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit CNX Gas’ ability to dispose of assets, make investments, purchase or redeem CNX Gas stock, pay dividends and merge with another corporation. This facility includes a leverage ratio covenant of not more than 3.00 to 1.00, measured quarterly. This ratio was 0.38 to 1.00 at December 31, 2009. The facility also includes an interest coverage ratio covenant of no less than 3.00 to 1.00, measured quarterly. This ratio was 68.17 to 1.00 at December 31, 2009. At December 31, 2009, this facility had approximately $15 million of letters of credit issued and had approximately $58 million of outstanding borrowings, leaving approximately $127 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.

Uncertainty in the financial markets brings additional potential risks to CNX Gas. The risks include 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. We have no indication that any such transactions would impact our current credit facility; however, the possibility does exist. Financial market disruptions may impact our collection of trade receivables. CNX Gas constantly monitors the creditworthiness of our customers. We believe that our current group of customers are sound and represent no abnormal business risk.

CNX Gas believes that cash generated from operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), scheduled debt payments, anticipated dividend payments and to provide required letters of credit. Nevertheless, the ability of CNX Gas to satisfy our working capital requirements, debt service obligations, to fund planned capital

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expenditures or pay dividends will depend upon future operating performance, which will be affected by prevailing economic conditions in the coal and gas industries and other financial and business factors, some of which are beyond CNX Gas’ control.

In order to manage the market risk exposure of volatile natural gas prices in the future, CNX Gas enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length. CNX Gas has 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 an asset of $117 million at December 31, 2009. The ineffective portion of these contracts was insignificant to earnings in the year ended December 31, 2009. Hedge counterparties consist of commercial banks who participate in the revolving credit facility. No issues related to our hedge agreements have been encountered to date.

CNX Gas frequently evaluates potential acquisitions. CNX Gas has funded acquisitions primarily with cash generated from operations and proceeds from our revolving credit facility. There can be no assurance that additional capital resources will be available to CNX Gas on terms which we find acceptable, or at all.

Cash Flows (in millions)

	2009			2008			Change
Cash provided by operating activities	$	360		$	447		$	(87	)
Cash used in investing activities	$	(335	)	$	(559	)	$	224
Cash (used in) provided by financing activities	$	(26	)	$	82		$	(108	)

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, 2009, we entered into hedging agreements covering 45.7 billion cubic feet, 22.6 billion cubic feet and 15.1 billion cubic feet for 2010, 2011 and 2012 respectively.

Cash flows from operating activities changed primarily due to the following items:

• Operating cash flow decreased in 2009 due to lower net income in the year-to-year comparison. Net income included higher amounts of depreciation, depletion and amortization in 2009 as discussed in the year-to-year operation analysis. Operating cash flows also decreased due to various other changes in operating assets, operating liabilities, other assets and other liabilities which occurred throughout both years.

• Operating cash flow in 2008 included an $8 million cash receipt from insurance carriers related to the Buchanan incident, as previously disclosed.

Net cash used in investing activities changed primarily due to the following items:

• Total capital expenditures decreased $188 million to $336 million in 2009 compared to $525 million in 2008. The $188 million decrease is primarily due to the slow-down of the drilling program related to the weak economic environment, offset, in part, by a $51 million increase due to Marcellus Shale drilling activity in Northern Appalachia.

• Cash used in investing activities is improved due to the $36 million expended in 2008 for the acquisition of the remaining portion of Knox Energy.

Net cash (used in) provided by financing activities changed primarily due to the following items:

• In 2009, CNX Gas repaid outstanding borrowings of $15 million to the revolving credit facility. In 2008, CNX Gas received proceeds of approximately $73 million from its revolving credit facility.

• In 2009, a variable interest entity in which CNX Gas is the primary beneficiary, although no ownership interest is held, repaid outstanding borrowings of $5 million on the variable rate note outstanding. In 2008, the variable interest entity received proceeds of $11 million on this note.

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Contractual Commitments

The following is a summary of our significant contractual obligations at December 31, 2009 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, at December 31, 2009 to be as follows:

	Within 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total
Short Term Debt Obligations—Revolver	$	57,850	$	—	$	—	$	—	$	57,850
Long Term Debt Obligations		4,603		10,062		—		—		14,665
Interest on Long Term Debt Obligation		830		308		—		—		1,138
Capital Lease Obligations		4,013		7,816		8,306		39,506		59,641
Interest on Capital Lease Obligations		4,548		7,607		6,466		10,870		29,491
Operating Lease Obligations		2,985		1,931		1,346		1,258		7,520
Other Long-term Liabilities:
Gas Firm Transportation Obligation		28,531		52,120		49,934		303,347		433,932
Other Liabilities(a)		5,200		4,600		5,200		8,420		23,420
Well Plugging Liabilities(b)		146		268		1,121		6,777		8,312
Post Retirement Benefits Other Than Pension		248		536		474		2,632		3,890
Purchase Obligations		11,555		—		—		—		11,555
Total Contractual Obligations(c)	$	120,509	$	85,248	$	72,847	$	372,810	$	651,414

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

(b) The ultimate settlement and timing cannot be precisely determined in advance.

(c) The significant obligation table does not include obligations to taxing authorities related to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations.

Debt

At December 31, 2009, CNX Gas had total long-term debt of $74 million outstanding, including the current portion of long-term debt of $9 million. This long-term debt consisted of:

• An aggregate principal amount of $59 million of capital leases with a weighted average interest rate of 7.23% per annum; and

• An aggregate principal amount of $15 million on a fixed rate note that bears interest at 6.10% at December 31, 2009. This note was incurred by a variable interest entity that is fully consolidated in which CNX Gas holds no ownership interest.

At December 31, 2009, CNX Gas had $58 million of aggregate principal amounts of outstanding borrowings and approximately $15 million of letters of credit outstanding under its $200 million revolving credit facility.

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 $1 billion.

Total Equity

CNX Gas had total equity of $1,507 million at December 31, 2009 and $1,385 million at December 31, 2008. The increase was primarily attributable to net income attributable to CNX Gas Shareholders for the year ended December 31, 2009 and amortization of stock-based compensation, offset, in part, by changes in cash flow hedging. See Consolidated Statements of Stockholders’ Equity in the Audited Consolidated Financial Statements in Item 8 of this Form 10-K.

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Total equity also changed due to the implementation of the Noncontrolling Interest Topic of the Financial Accounting Standards Board Accounting Standards Codification. This topic required minority interest to be recharacterized as noncontrolling interests, and classified as a component of equity for all periods presented as of January 1, 2009.

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. CNX Gas uses a combination of surety bonds, corporate guarantees and letters of credit to secure our financial obligations for employee-related, environmental, deliveries and various other items which are not reflected on the balance sheet at December 31, 2009. Management believes these items will expire without being funded. See Note 20—Commitments and Contingent Liabilities in the Audited Consolidated Financial Statements in Item 8.

Recent Accounting Pronouncements

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities. This guidance shall be effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. Earlier application is prohibited. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have a material impact on CNX Gas’ financial statements.

Item 7A. Quantitative and Qualitative Disclosure About Market Risk

In addition to the risks inherent in 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, interest rates and foreign exchange rates.

CNX Gas is exposed to market price risk in the normal course of selling natural gas production. CNX Gas uses fixed-price contracts, collar-price contracts and derivative commodity instruments that qualify as cash-flow hedges under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification 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 its asset base. All of the derivative instruments are held for purposes other than trading. They are used primarily to mitigate 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 our 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 in Item 8 of this Form 10-K.

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Sensitivity analyses of the incremental effects on pre-tax income for the year ended December 31, 2009 of a hypothetical 10 percent and 25 percent change in natural gas prices for open derivative instruments as of December 31, 2009 are provided in the following table:

	Incremental Decrease in Pre-tax Income Assuming a Hypothetical Price, Exchange Rate or Interest Rate Change of:
	10%		25%
	(in millions)
Natural Gas(a)	$	22.4	$	51.2

(a) CNX Gas remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be offset by price changes in the underlying hedged item. CNX Gas entered into derivative instruments to convert the market prices related portions of the 2010 through 2012 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. We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

Hedging Volumes

As of January 6, 2010, our hedged volumes for the periods indicated are as follows:

	Three Months Ended March 31,		Three Months Ended June 30,		Three Months Ended September 30,		Three Months Ended December 31,		Total Year
2010 Fixed Price Volumes
Hedged Mcf		12,989,691		13,603,093		12,659,794		8,221,649		47,474,227
Weighted Average Hedge Price/Mcf	$	8.76	$	8.15	$	7.56	$	6.54	$	7.88
2011 Fixed Price Volumes
Hedged Mcf		5,567,010		5,628,866		5,690,722		5,690,722		22,577,320
Weighted Average Hedge Price/Mcf	$	6.84	$	6.84	$	6.84	$	6.84	$	6.84
2012 Fixed Price Volumes
Hedged Mcf		3,752,577		3,752,577		3,793,815		3,793,815		15,092,784
Weighted Average Hedge Price/Mcf	$	6.84	$	6.84	$	6.84	$	6.84	$	6.84

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 “Liquidity and Capital Resources” 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, 2009, CNX Gas had $74 million aggregate principal amount of debt outstanding under fixed-rate instruments and $58 million aggregate principal amount of debt outstanding under variable-rate instruments. CNX Gas’ primary exposure to market risk for changes in interest rates relates to our revolving credit facility. CNX Gas’ facility had outstanding borrowings of $58 million at December 31, 2009 and bore interest at a weighted average rate of 1.47% per annum during the year ended December 31, 2009. Due to the level of borrowings against this facility and the low weighted average interest rate in the year ended December 31, 2009, 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 of CNX Gas’ transactions are denominated in U.S. dollars, and, as a result, it does not have material 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’	56
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007	58
Consolidated Balance Sheets as of December 31, 2009 and 2008	59
Consolidated Statements of Stockholders’ Equity for the years ended December  31, 2009, 2008 and 2007	60
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	61
Notes to Audited Financial Statements	62

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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 sheets of CNX Gas Corporation (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years 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, 2009 and 2008, and the consolidated results of their operations and their cash flows for the years then ended, in conformity with U.S. generally accepted accounting principles.

As discussed in Note 1 to the consolidated financial statements, the Company has changed its reserve estimates and related disclosures as a result of adopting new oil and gas reserve estimation and disclosure requirements. As discussed in Note 12 to the consolidated financial statements, during the year ended December 31, 2008, the Company adopted the measurement provisions related to pension and other postretirement benefit obligations.

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, 2009, 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 9, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, PA

February 9, 2010

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Report of Independent Registered Public Accounting Firm

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

In our opinion, the consolidated statements of income, stockholders’ equity and cash flows for the year ended December 31, 2007 present fairly, in all material respects, the results of CNX Gas Corporation and its subsidiaries (CNX Gas) operations and their cash flows for the year ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of CNX Gas Corporation’s management. Our responsibility is to express an opinion on these financial statements 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.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 15, 2008

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CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

	For the Years Ended December 31,
	2009			2008		2007
Revenue and Other Income:
Outside Sales	$	627,419		$	678,793	$	404,835
Related Party Sales		3,179			9,532		11,618
Royalty Interest Gas Sales		40,951			79,302		46,586
Purchased Gas Sales		7,040			8,464		7,628
Other Income		4,855			13,330		8,815
Total Revenue and Other Income		683,444			789,421		479,482
Costs and Expenses:
Lifting Costs		55,285			67,653		38,721
Gathering and Compression Costs		95,687			83,752		61,798
Royalty Interest Gas Costs		32,423			74,041		40,011
Purchased Gas Costs		6,442			8,175		7,162
Exploration and Other Costs		17,201			4,995		1,759
General and Administrative		66,655			59,244		42,664
Other Corporate Expenses		32,871			21,002		12,161
Depreciation, Depletion and Amortization		107,251			70,010		48,961
Interest Expense		7,568			7,820		5,606
Total Costs and Expenses		421,383			396,692		258,843
Earnings Before Income Taxes and Noncontrolling Interest		262,061			392,729		220,639
Noncontrolling Interest		(1,037	)		—		—
Earnings Before Income Taxes		263,098			392,729		220,639
Income Taxes		98,636			153,656		84,961
Net Income Attributable to CNX Gas Shareholders	$	164,462		$	239,073	$	135,678
Earnings Per Share:
Basic	$	1.09		$	1.58	$	0.90
Dilutive	$	1.09		$	1.58	$	0.90
Weighted Average Number of Common Shares Outstanding:
Basic		150,977,235			150,947,516		150,886,433
Dilutive		151,325,146			151,331,953		151,133,520

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

58

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2009			2008
ASSETS
Current Assets:
Cash and Cash Equivalents	$	1,124		$	1,926
Accounts and Notes Receivable:
Trade		43,421			61,764
Other Receivables		975			3,080
Recoverable Income Taxes		—			30,302
Derivatives		99,265			150,564
Other		3,829			2,222
Total Current Assets		148,614			249,858
Property, Plant and Equipment:
Property, Plant and Equipment		2,409,751			2,113,570
Less—Accumulated Depreciation, Depletion and Amortization		433,201			322,470
Total Property, Plant and Equipment—Net		1,976,550			1,791,100
Other Assets:
Investment in Affiliates		24,591			25,204
Derivatives		18,218			55,945
Other		3,409			2,866
Total Other Assets		46,218			84,015
TOTAL ASSETS	$	2,171,382		$	2,124,973
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	53,516		$	100,565
Accrued Royalties		14,898			20,301
Accrued Severance Taxes		1,037			3,672
Related Parties		5,171			2,234
Short-Term Notes Payable		57,850			72,700
Deferred Income Taxes		34,871			55,000
Accrued Income Taxes		31,765			—
Current Portion of Long-Term Debt		8,616			8,462
Other Current Liabilities		9,520			18,116
Total Current Liabilities		217,244			281,050
Long-Term Debt:
Long-Term Debt		10,062			15,386
Capital Lease Obligations		55,628			59,296
Total Long-Term Debt		65,690			74,682
Deferred Credits and Other Liabilities:
Deferred Income Taxes		334,493			331,338
Gas Well Plugging		8,312			7,401
Postretirement Benefits Other Than Pensions		3,642			2,728
Other		35,101			42,900
Total Deferred Credits and Other Liabilities		381,548			384,367
Total Liabilities		664,482			740,099
Stockholders’ Equity:
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,986,918 Issued and Outstanding at December 31, 2009 and 150,971,636 Issued and Outstanding at December 31, 2008		1,510			1,510
Capital in Excess of Par Value		806,527			789,625
Preferred Stock, 5,000,000 Shares Authorized; None Issued and Outstanding		—			—
Retained Earnings		633,417			468,955
Other Comprehensive Income		69,816			124,784
Total CNX Gas Shareholders’ Equity		1,511,270			1,384,874
Noncontrolling Interest		(4,370	)		—
Total Equity		1,506,900			1,384,874
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	2,171,382		$	2,124,973

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

59

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands)

	Common Stock		Capital in Excess of Par Value		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total CNX Gas Stockholders’ Equity			Noncontrolling Interest			Total Equity
Balance at December 31, 2006	$	1,508	$	781,960	$	94,337		$	2,410		$	880,215		$	—		$	880,215
Net Income Attributable to CNX Gas Shareholders		—		—		135,678			—			135,678			—			135,678
Gas Cash Flow Hedge (Net of $2,145 tax)		—		—		—			4,214			4,214			—			4,214
Actuarially Determined Liabilities Adjustment (Net of $278 tax)		—		—		—			(433	)		(433	)		—			(433	)
Comprehensive Income		—		—		135,678			3,781			139,459			—			139,459
Uncertain Tax Position Adoption		—		—		(53	)		—			(53	)		—			(53	)
Stock Options Exercised		1		302		—			—			303			—			303
Tax Benefit from Stock-Based Compensation		—		53		—			—			53			—			53
Amortization of Stock-Based Compensation Awards		—		3,260		—			—			3,260			—			3,260
Balance at December 31, 2007	$	1,509	$	785,575	$	229,962		$	6,191		$	1,023,237		$	—		$	1,023,237
Net Income Attributable to CNX Gas Shareholders		—		—		239,073			—			239,073			—			239,073
Gas Cash Flow Hedge (Net of $77,291 tax)		—		—		—			118,646			118,646			—			118,646
Issuance of Common Stock		1		—		—			—			1			—			1
Amortization of Prior Service Costs and Actuarial Losses (Net of $52 tax)		—		—		—			(83	)		(83	)		—			(83	)
Actuarially Determined Liabilities Adjustment (Net of $108 tax)		—		—		—			50			50			—			50
Comprehensive Income		1		—		239,073			118,613			357,687			—			357,687
Cumulative Effect of Actuarially Determined Liabilities Measurement Adoption (Net of $64 tax)		—		—		(80	)		(20	)		(100	)		—			(100	)
Stock Options Exercised		—		292		—			—			292			—			292
Tax Benefit from Stock-Based Compensation		—		380		—			—			380			—			380
Amortization of Stock-Based Compensation Awards		—		3,378		—			—			3,378			—			3,378
Balance at December 31, 2008	$	1,510	$	789,625	$	468,955		$	124,784		$	1,384,874		$	—		$	1,384,874
Net Income Attributable to CNX Gas Shareholders		—		—		164,462			—			164,462			—			164,462
Gas Cash Flow Hedge (net of $34,932 tax)		—		—		—			(53,132	)		(53,132	)		—			(53,132	)
Actuarially Determined Liabilities Adjustment (Net of $1,186 tax)		—		—		—			(1,836	)		(1,836	)		—			(1,836	)
Comprehensive Income (Loss)		—		—		164,462			(54,968	)		109,494			—			109,494
Stock Options Exercised		—		200		—			—			200			—			200
Tax Benefit from Stock-Based Compensation		—		44		—			—			44			—			44
Amortization of Restricted Stock Unit Grants		—		15,119		—			—			15,119			—			15,119
Amortization of Stock Option Grants		—		1,539		—			—			1,539			—			1,539
Noncontrolling Interest		—		—		—			—			—			(4,370	)		(4,370	)
Balance at December 31, 2009	$	1,510	$	806,527	$	633,417		$	69,816		$	1,511,270		$	(4,370	)	$	1,506,900

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

60

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	For the Years Ended December 31,
	2009			2008			2007
Operating Activities:
Net Income Attributable to CNX Gas Shareholders	$	164,462		$	239,073		$	135,678
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization		107,251			70,010			48,961
Stock-based Compensation		6,311			3,378			3,260
Loss on the Sale of Assets		72			—			—
Change in Noncontrolling Interest		(1,037	)		—			—
Deferred Income Taxes		31,896			117,870			70,352
Equity in Earnings of Affiliates		(637	)		(551	)		(2,174	)
Changes in Operating Assets:
Accounts Receivable		20,448			(21,789	)		8,267
Related Party Receivable		2,937			3,256			1,723
Other Current Assets		(1,607	)		191			770
Changes in Other Assets		(505	)		3,861			2,294
Changes in Operating Liabilities:
Accounts Payable		(21,845	)		33,531			2,732
Income Taxes		52,572			(28,515	)		(4,171	)
Other Current Liabilities		(15,614	)		16,668			3,193
Changes in Other Liabilities		(1,369	)		10,611			1,968
Other		16,828			(219	)		(405	)
Net Cash Provided by Operating Activities		360,163			447,375			272,448
Investing Activities:
Capital Expenditures		(336,447	)		(524,663	)		(295,422	)
Acquisition of Knox Energy		—			(36,000	)		—
Acquisition of Mineral Rights		—			—			(61,777	)
Investment in Equity Affiliates		1,250			1,081			2,785
Proceeds From Sale of Assets		288			450			187
Net Cash Used in Investing Activities		(334,909	)		(559,132	)		(354,227	)
Financing Activities:
Capital Lease Payments		(3,750	)		(2,769	)		(2,552	)
Variable Interest Entity Debt		(5,218	)		11,032			8,851
(Payments on) Proceeds from Short-Term Borrowings		(14,850	)		72,700			—
Exercise of Stock Options		200			292			302
Noncontrolling Interest Distribution		(2,500	)		—			—
Tax Benefit from Stock-Based Compensation		62			380			53
Net Cash (Used in) Provided by Financing Activities		(26,056	)		81,635			6,654
Net Decrease in Cash and Cash Equivalents		(802	)		(30,122	)		(75,125	)
Cash and Cash Equivalents at Beginning of Period		1,926			32,048			107,173
Cash and Cash Equivalents at End of Period	$	1,124		$	1,926		$	32,048

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

See Note 16—Supplemental Cash Flow Information

61

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 accounts of variable interest entities (VIEs), as defined by the Financial Accounting Standards Board (FASB) Accounting Standards Codification, where CNX Gas is the primary beneficiary, are included in the Consolidated Financial Statements.

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, gas well plugging liabilities, income taxes and stock based compensation.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and deposits at 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. Collectability is determined based on terms of sale, credit status of customer and various other circumstances. CNX Gas regularly reviews collectability 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

62

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

be non-productive, or if the determination is made to discontinue 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.

Upon the sale or retirement of a 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 units of production method. Wells and related equipment and intangible drilling costs are amortized on a units-of-production method. 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 tax return that would be filed on a separate company basis. Deferred taxes result from differences between the financial and tax basis 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.

Gas Well Plugging Liabilities

CNX Gas accrues for the dismantling and removal costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the Financial Accounting Standards Board Accounting Standards Codification. This requires the fair value of a gas well plugging liability 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 gas well plugging liability is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized gas well plugging cost is generally determined on a units-of-production

63

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

basis. Accretion of the gas well plugging liability 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.

Accrued costs of dismantling and removal of 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 various pipeline operators. The imbalance agreements are managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken by the purchaser.

Royalty Interest Gas Sales represent the revenues for 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 the Nonmonetary Transactions Topic of the FASB Accounting Standards Codification. Therefore these transactions are reflected net on the Consolidated Statement of Income within 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 Statements 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, 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,

64

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 the Derivatives and Hedging Topic of the FASB Accounting Standards Codification. 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 the fair value 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

Stock-based compensation expense for all stock-based compensation awards is based on the grant date fair value estimated in accordance with the provisions of Stock Compensation Topic of the FASB Accounting Standards Codification. 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 14 to the Consolidated Financial Statements for further discussion of 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, 2009, 2008 and 2007. 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 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. The table below sets forth the outstanding options and unvested restricted stock units that have been excluded from the computation of diluted earnings per share because their effect would be anti-dilutive.

	For the Years Ended December 31,
	2009	2008	2007
Anti-Dilutive Options	2,000	17,175	490,056
Anti-Dilutive Restricted Stock Units	815	—	—
	2,815	17,175	490,056

65

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The computations for basic and dilutive earnings per share from continuing operations are as follows:

	For the Years Ended December 31,
	2009		2008		2007
Net Income Attributable to CNX Gas Shareholders	$	164,462	$	239,073	$	135,678
Average shares of common stock outstanding:
Basic		150,977,235		150,947,516		150,886,433
Effect of stock-based compensation awards		347,911		384,437		247,087
Dilutive		151,325,146		151,331,953		151,133,520
Earnings per share:
Basic	$	1.09	$	1.58	$	0.90
Dilutive	$	1.09	$	1.58	$	0.90

Shares of common stock outstanding were as follows:

	2009	2008	2007
Balance, beginning of year	150,971,636	150,915,198	150,864,075
Issuance related to stock-based compensation(1)	15,282	56,438	51,123
Balance, end of year	150,986,918	150,971,636	150,915,198

(1) See Note-14 Stock-Based Compensation for additional information.

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

CNX Gas accounts for its business acquisitions under the purchase method of accounting consistent with the requirements of the Business Combination Topic of the FASB Accounting Standards Codification. 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.

Recently Adopted Accounting Guidance

In December 2009, CNX Gas adopted the authoritative guidance issued by the FASB on extractive activities for oil and gas reserve estimation and disclosures. The objective of the new guidance is to align the oil and gas reserve estimation and disclosure requirements with the requirements of the Securities and Exchange Commission. The new guidance, among other purposes, is primarily intended to provide investors with a more

66

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

meaningful and comprehensive understanding of oil and gas reserves by expanding the definition of proved oil and gas producing activities, disclosing geographical areas that represent a certain percentage of proved reserves, updating the reserve estimation requirements for changes in practice and technology that have occurred over the past several decades and requiring that an entity continue to disclose separately the amounts and quantities for consolidated and equity method investments. CNX Gas has applied this guidance to its Financial Statements for the year ended December 31, 2009.

Recent Accounting Guidance Not Yet Adopted

In June 2009, the FASB issued authoritative guidance on the consolidation of variable interest entities. This Statement shall be effective as of the beginning of each reporting entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. Earlier application is prohibited. The new guidance requires revised evaluations of whether entities represent variable interest entities, ongoing assessments of control over such entities, and additional disclosures for variable interests. We believe adoption of this new guidance will not have a material impact on CNX Gas’ financial statements.

Reclassifications

Certain amounts in prior periods have been reclassified to conform to the report classifications of the year ended December 31, 2009 with no effect on previously reported net income or stockholders’ equity. These reclassifications include amounts related to Other Assets, Property, Plant and Equipment, and General Administrative and Other Corporate Expenses.

Subsequent Events

We have evaluated all subsequent events through February 9, 2010, the date the financial statements were issued. No material recognized or non-recognizable subsequent events were identified.

Note 2—Significant Acquisitions and Dispositions:

In August 2009, CNX Gas completed the lease assignment, to a third party, of the Company’s previous corporate headquarters. Total expense related to this transaction for the year ended December 31, 2009 was $1,500, which was recognized in Other Corporate Expenses.

In July 2009, CNX Gas leased approximately 40,000 acres having Marcellus Shale potential in two separate transactions. The transactions included leasing 20,000 acres from NiSource Energy Ventures, LLC, a subsidiary of Columbia Energy Group, for a cash payment of $8,275 and 20,000 acres from our majority owner, CONSOL Energy, for a cash payment of $9,966. The purchase price for both transactions was principally allocated to proved and unproved properties and is included in Capital Expenditures in the Consolidated Statements of Cash Flows.

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.

67

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

In June 2008, CNX Gas completed the acquisition of the remaining 50% interest in Knox Energy, LLC and Coalfield Pipeline not already owned, for a cash payment of $36,000, which was principally allocated to proved properties, wells and equipment and gathering assets. Knox Energy, LLC had been proportionately consolidated into CNX Gas’ financial statements from December 31, 2007 until acquisition date and Coalfield Pipeline was accounted for under the equity method. 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 to acquire certain oil and gas, coalbed methane, and other gas interests. Pursuant to the transaction, CNX Gas acquired certain coal assets from CONSOL Energy for $45,000 cash, plus $1,777 of miscellaneous acquisition costs, plus a future payment with an estimated present value at December 31, 2009 of $7,375, 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 had no proved gas reserves. The purchase price for the transactions was principally allocated to unproved properties and is included in Capital Expenditures in the Consolidated Statements of Cash Flows.

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 $1,671, $7,337, and $6,242 for the years ended December 31, 2009, 2008 and 2007, 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 $1,508, $2,195, and $5,376 for the years ended December 31, 2009, 2008 and 2007, respectively.

CNX Gas has a note payable due in May 2042 to its majority shareholder CONSOL Energy. The note resulted from the acquisition of certain oil and gas, coalbed methane, and other gas interests in the year ended December 31, 2007. At December 31, 2009, the present value of this future payment is $7,375 which is included in Other Liabilities in the Consolidated Balance Sheet.

CNX Gas also purchases various supplies from CONSOL Energy’s wholly owned subsidiary, Fairmont Supply. The costs of these purchases reflect current market prices and are included in Lifting Costs, Gathering and Compression Costs and Capital Expenditures as arms-length transactions. Fairmont Supply also operates the Company’s warehouse facilities. CNX Gas paid Fairmont Supply $4,623, $2,434, and $699 for the years ended December 31, 2009, 2008 and 2007, respectively.

CNX Gas entered into two separate transactions with CONSOL Energy to acquire acreage with Marcellus Shale potential. These transactions totaled $14,320 and were principally allocated to proved and unproved properties and were included in Capital Expenditures for the year ended December 31, 2009.

68

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 $25,352, $3,213, and $1,635 for the years ended December 31, 2009, 2008 and 2007, respectively. The increased general and administrative allocation is attributable to the management consolidation with CONSOL Energy. The consolidation, which was effective April 1, 2009, resulted in employees being transferred from CNX Gas to CONSOL Energy. Services previously provided by the CNX Gas employees are now provided by CONSOL Energy, and accordingly, charged to CNX Gas. These general and administrative fees were allocated to CNX Gas based on various methods, including a proportionate share of mancount, a proportionate share of capital expenditures, a proportionate share of revenue earned, or a combination of these methods. For the years ended December 31, 2008 and 2007, the costs included certain accounting and other administrative services provided by CONSOL Energy.

Other corporate expenses contain a charge for $11,753 for the year ended December 31, 2009, related to short-term incentive compensation allocated from CONSOL Energy. The CONSOL Energy short-term incentive compensation expenses are now allocated to CNX Gas due to the management consolidation which was effective April 1, 2009. The management consolidation resulted in a significant amount of CNX Gas personnel being transferred to CONSOL Energy. Costs of the CONSOL Energy short-term incentive compensation plan are now allocated to CNX Gas based on the overall general and administrative allocation.

Other corporate expenses also contains a charge for $6,036 for the year ended December 31, 2009, related to stock-based compensation allocated from CONSOL Energy. The CONSOL Energy stock-based compensation expenses are now allocated to CNX Gas due to the management consolidation which was effective April 1, 2009. The management consolidation resulted in a significant amount of CNX Gas personnel being transferred to CONSOL Energy. Costs of the CONSOL Energy stock-based compensation plan are now allocated to CNX Gas based on the overall general and administrative allocation.

CNX Gas paid, net of refunds received, CONSOL Energy $5,577, $61,397 and $18,676 for federal income taxes for years ended December 31, 2009, 2008 and 2007, 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 $13,662, $14,073, and $7,101 for the years ended December 31, 2009, 2008 and 2007, respectively. 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 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 $1,364, $1,757 and $1,233 for the years ended December 31, 2009, 2008 and 2007, 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 years ended December 31, 2009 and 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. See Note 12 to the Consolidated Financial Statements for further information.

69

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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 $329, $577 and $493 for the years ended December 31, 2009, 2008 and 2007, 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. Amounts charged to expense by CNX Gas for these benefit plans were $115, $147 and $113 for the years ended December 31, 2009, 2008 and 2007, respectively. The plan also 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 2010 and instead expects to pay benefit claims as they become due.

CONSOL Energy has provided financial guarantees on behalf of CNX Gas. As discussed in Note 20 to the Consolidated Financial Statements. We believe that these parental guarantees will expire without being funded, and therefore will not have a material adverse effect on the financial statements.

Note 4—Other Income:

	For the Years Ended December 31,
	2009		2008		2007
Third party gathering revenue	$	2,533	$	1,601	$	1,077
Timber income		750		768		99
Equity in earnings		637		551		2,174
Legal settlement		437		650		—
Interest income		64		400		3,793
Business interruption insurance		—		8,000		1,600
Miscellaneous		434		1,360		72
Total Other Income	$	4,855	$	13,330	$	8,815

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 Years Ended December 31,
	2009					2008					2007
	Amount			Percent		Amount			Percent		Amount			Percent
Statutory U.S. federal income tax rate.	$	92,084		35.0	%	$	137,455		35.0	%	$	77,223		35.0	%
Net effect of state income taxes.		10,868		4.1			16,945		4.3			9,108		4.1
Effect of Domestic Production Activities Deductions		(3,571	)	(1.4	)		(1,863	)	(0.5	)		(783	)	(0.4	)
Other		(745	)	(0.2	)		1,119		0.3			(587	)	(0.2	)
Income Tax Expense / Effective Rate.	$	98,636		37.5	%	$	153,656		39.1	%	$	84,961		38.5	%

70

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, local, or non-U.S. income tax examinations by tax authorities for years prior to 2005. The Internal Revenue Service (IRS) commenced an examination of CONSOL Energy’s U.S. income tax returns for 2006 and 2007. This examination is anticipated to be completed in the fourth quarter of 2010. As of December 31, 2009, 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.

Income taxes on earnings consisted of:

	For the Years Ended December 31,
	2009		2008		2007
Current:
Federal.	$	55,311	$	29,622	$	13,836
State.		11,429		6,164		2,755
		66,740		35,786		16,591
Deferred:
Federal.		26,606		98,144		57,112
State.		5,290		19,726		11,258
		31,896		117,870		68,370
Total Income Tax Expense.	$	98,636	$	153,656	$	84,961

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

	As of December 31,
	2009			2008
Deferred Tax Assets:
Capital Lease Obligations.	$	22,916		$	23,924
Stock-Based Compensation.		5,692			1,868
Gas Well Plugging.		3,018			2,904
Postretirement Benefits Other than Pension.		2,313			1,154
Other.		11,918			7,844
Total Deferred Tax Assets.		45,857			37,694
Deferred Tax Liabilities:
Property, Plant and Equipment.		(362,859	)		(338,435	)
Derivatives.		(46,129	)		(81,061	)
Investment in Equity Affiliates.		(4,618	)		(4,536	)
Other.		(1,615	)		—
Total Deferred Tax Liabilities.		(415,221	)		(424,032	)
Net Deferred Tax Liabilities.	$	(369,364	)	$	(386,338	)

During the years ended December 31, 2009 and 2008, the Company recognized an increase in the liability relating to unrecognized tax benefits of $3,276 and $1,012, respectively. The balance of unrecognized tax benefits as of December 31, 2009 and 2008 was $8,821 and $5,545, respectively. The unrecognized tax changes

71

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

include tax positions for which 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 2009 and 2008 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:

	As of December 31,
	2009		2008
Balance at beginning of period.	$	5,545	$	4,533
Additions related to current year tax positions.		778		1,012
Additions related to prior year tax positions.		2,498		—
Balance at end of period.	$	8,821	$	5,545

CNX Gas recognizes interest accrued related to unrecognized tax benefits in its interest expense. As of December 31, 2009 and 2008, CNX Gas reported an accrued interest liability relating to uncertain tax positions of $971 and $516, respectively. Interest expense relating to uncertain tax positions of $455, $334 and $90 is reflected in the Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007, respectively.

CNX Gas recognizes penalties accrued related to unrecognized tax benefits in its income tax expense. As of December 31, 2009, 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—Gas Well Plugging

CNX Gas accrues for the dismantling and removal costs of gas related facilities using the accounting treatment prescribed by the Asset Retirement and Environmental Obligations Topic of the Financial Accounting Standards Board (FASB) Accounting Standards Codification. 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 Gas Well Plugging Obligations at December 31, 2009 and 2008 is as follows:

	As of December 31,
	2009			2008
Balance at beginning of period	$	7,401		$	3,981
Accretion expense		692			460
Payments		(123	)		—
Liabilities incurred		138			1,943
Revisions in estimated cash flows		204			1,017
Balance at end of period	$	8,312		$	7,401

72

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

For the year ended December 31, 2009, the revisions in estimated cash flows are due primarily to the effect on the present value of changes in the expected timing of plugging wells. 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.

Note 7—Property, Plant and Equipment:

	As of December 31,
	2009			2008
Leasehold Improvements	$	—		$	1,352
Proved Properties		152,010			121,605
Unproved Properties		271,553			220,848
Wells and Related Equipment		253,833			222,685
Intangible Drilling		913,231			793,456
Gathering Assets		804,212			740,396
Gas Well Plugging		4,082			3,739
Capitalized Internal Software		8,130			7,302
Advance Royalties		2,700			2,187
Total Property, Plant and Equipment		2,409,751			2,113,570
Accumulated Depreciation, Depletion and Amortization		(433,201	)		(322,470	)
Property and Equipment, net	$	1,976,550		$	1,791,100

Property, plant and equipment includes gross assets acquired under capital leases of $69,707 and $69,990 at December 31, 2009 and 2008, respectively. Related amounts in accumulated depreciation, depletion and amortization are $15,738 and $10,900 at December 31, 2009 and 2008, 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 0.38 to 1.00 at December 31, 2009. 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 68.17 to 1.00 at December 31, 2009.

At December 31, 2009, the CNX Gas credit agreement had outstanding borrowings of $57,850 and $14,913 of letters of credit outstanding, leaving $127,237 of capacity available for borrowings and the issuance of letters of credit. The facility bore a weighted average interest rate of 1.69% and 2.01% as of December 31, 2009 and 2008, respectively.

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.

73

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 9—Other Current Liabilities:

	As of December 31,
	2009		2008
Short Term Incentive Compensation Plan	$	3,489	$	8,108
Accrued Firm Transportation		1,936		1,380
Accrued Payroll and Benefits		1,140		2,416
Accrued Property Taxes		635		2,894
Purchased Gas		587		1,256
Other		1,733		2,062
Total Other Current Liabilities	$	9,520	$	18,116

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, 2009, are as follows:

Year Ended December 31, 2009	Capital Leases		Operating Leases
2010	$	8,562	$	2,985
2011		7,860		1,180
2012		7,563		751
2013		7,394		714
2014		7,380		632
Thereafter		50,373		1,258
Total minimum lease payments	$	89,132	$	7,520
Less amount representing interest (0.63% - 7.36%)		29,491
Present value of minimum lease payments		59,641
Less amount due in one year		4,013
Total Long-Term Lease Obligation	$	55,628

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 $11,628, $9,381, and $6,675 for the years ended December 31, 2009, 2008 and 2007 respectively.

74

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 11—Long-Term Debt:

	December 31,
	2009		2008
Debt:
Note Payable—Huntington National Bank, due 2011 at 6.10%.	$	14,628	$	18,940
Note Payable—CNH Capital, due 2011 at 7.50%.		37		59
Members loans payable, due various undetermined dates, no interest.		—		621
Other notes payable, due various dates through 2011 with interest ranging from 7.350% to 10.423%.		—		263
Total Debt.		14,665		19,883
Less amounts due in one year.		4,603		4,497
Total Long-Term Debt.	$	10,062	$	15,386

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

2010.	$	4,603
2011.		10,062
Total Long-Term Debt Maturities.	$	14,665

Note 12—Pension and Other Postretirement Benefits:

CNX Gas participates in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The benefits for this plan are based primarily on years of service and employees’ compensation near retirement. Employees hired on or after January 1, 2007 are not eligible to participate in the defined benefit retirement plan; instead they receive an additional 3% company contribution into their defined contribution plan.

During 2009, the CNX Gas pension plan was merged into the CONSOL Energy pension plan. The benefits provided did not change. According to the Master Separation Agreement between CNX Gas and CONSOL Energy, the plan will continue to be valued on a stand-alone basis. Additionally, during the year ended December 31, 2009 certain CNX Gas employees became eligible to participate in the CONSOL Energy Supplemental Retirement Plan. The benefit liabilities for these employees have been reflected as Plan Amendments in the reconciliation of the change in benefit obligation for the year ended December 31, 2009.

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 one thousand dollars 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.

CNX Gas adopted the measurement provisions of the Defined Benefit Plans Topic of the FASB Accounting Standards Codification during the year ended December 31, 2008. As a result of this adoption, the Company

75

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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.

The reconciliation of changes in the benefit obligation, plan assets and funded status of this plan at December 31, 2009 and 2008 is as follows:

	Pension Benefits at December 31,						Other Benefits at December 31,
	2009			2008			2009			2008
Change in benefit obligation:
Benefit obligation at beginning of year	$	1,145		$	615		$	2,882		$	2,814
Service cost (9/30/07-12/31/07)		—			80			—			33
Service cost		293			323			183			132
Interest cost (9/30/07-12/31/07)		—			10			—			46
Interest cost		85			40			292			183
Actuarial loss (gain)		56			110			648			(145	)
Plan amendments		2,378						—
Benefits paid (9/30/07-12/31/07)		—			(5	)		—			(34	)
Benefits paid		(38	)		(28	)		(115	)		(147	)
Benefit obligation at end of period	$	3,919		$	1,145		$	3,890		$	2,882
Change in plan assets:
Fair value of plan assets at beginning of period	$	816		$	288		$	—		$	—
Actual return on plan assets		195			—			—			—
Company contributions (9/30/07-12/31/07)		—			43			—			33
Company contributions		660			518			115			147
Benefits and other payments (9/30/07-12/31/07)		—			(5	)		—			(33	)
Benefits paid		(38	)		(28	)		(115	)		(147	)
Fair value of plan assets at end of period	$	1,633		$	816		$	—		$	—
Funded status:
Noncurrent assets	$	92		$	—		$	—		$	(154	)
Current liabilities		—			—			(248	)		—
Noncurrent liabilities		(2,378	)		(329	)		(3,642	)		(2,728	)
Net obligation recognized	$	(2,286	)	$	(329	)	$	(3,890	)	$	(2,882	)
Amounts recognized in accumulated other comprehensive income consist of:
Net actuarial (gain) loss	$	(6	)	$	46		$	1,104		$	579
Prior service cost (credit)		2,378			—			(901	)		(1,072	)
Net amount recognized (before tax effect)	$	2,372		$	46		$	203		$	(493	)

76

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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,
	2009			2008			2007			2009			2008			2007
Components of net periodic benefit cost:
Service cost	$	293		$	323		$	262		$	183		$	132		$	124
Interest cost		85			40			12			292			183			139
Expected return on plan assets		(100	)		(25	)		(2	)		—			—			—
Amortization of prior service cost (credit)		—			—			—			(172	)		(172	)		(172	)
Recognized net actuarial (gain) loss		14			—			(23	)		124			36			21
Benefit cost	$	292		$	338		$	249		$	427		$	179		$	112

Amounts included in accumulated other comprehensive income, expected to be recognized in 2010 net periodic benefit costs:

	Pension Benefits		Postretirement Benefits
Prior service cost (benefit) recognition	$	264	$	(172	)
Actuarial loss recognition	$	—	$	49

The accumulated benefit obligation for the Pension Plan at December 31, 2009 and 2008 was $ 793 and $894, respectively.

Assumptions:

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

	Pension Benefits at December 31,				Other Benefits at December 31,
	2009		2008		2009		2008
Discount rate	5.79	%	6.28	%	5.87	%	6.20	%
Rate of compensation increase	4.50	%	5.34	%	—		—

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

	Pension Benefits at December 31,						Other Benefits at December 31,
	2009		2008		2007		2009		2008		2007
Discount rate	6.28	%	6.57	%	6.00	%	6.20	%	6.63	%	6.00	%
Expected long-term return on plan assets	8.00	%	8.00	%	8.00	%	—		—		—
Rate of compensation increase	5.34	%	5.46	%	4.36	%	—		—		—

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

77

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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,
	2009		2008		2007
Healthcare cost trend rate for next year	8.74	%	9.60	%	8.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	5.00	%	5.00	%
Year that the rate reaches ultimate trend rate	2023		2015		2013

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-Percentage Point Increase		1-Percentage Point Decrease
Effect on total of service and interest costs components	$	49	$	(55	)
Effect on accumulated postretirement benefit obligation	$	209	$	(275	)

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 Percentage Point Increase			0.25 Percentage Point Decrease
Pension benefit costs (decrease) increase	$	(12	)	$	12
Other postemployment benefits costs (decrease) increase	$	(17	)	$	18

Plan Assets:

The merger of the CNX Gas pension plan into the CONSOL Energy pension plan during 2009 resulted in the CNX Gas plan assets being merged with the CONSOL Energy plan assets. As of December 31, 2009, the combined plan assets held by the trustees of the CONSOL Energy pension plan are invested in various investment securities. As of December 31, 2008, all of the plan assets were held in cash and cash equivalents. CNX Gas had no plan assets as of December 31, 2009 and 2008 for other postretirement benefits.

Cash Flows:

We expect to contribute $150 to the Pension Plan in 2010. The Company does not expect to contribute to the other postretirement benefit plan in 2010. 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
2010	$	26	$	248
2011	$	30	$	270
2012	$	35	$	266
2013	$	42	$	255
2014	$	50	$	220
Year 2015-2019	$	810	$	1,196

78

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 13—Variable Interest Entities:

CNX Gas has a business relationship with a contractor to perform CNX Gas’ well drilling requirements primarily in Northern Appalachia. CNX Gas is the primary customer of the contractor. In addition, as of December 31, 2009, CNX Gas has guaranteed the outstanding principal balance of a loan agreement between the contractor and Huntington National Bank, amended August 27, 2009. The contractor has been determined to be a variable interest entity and CNX Gas is the primary beneficiary. Under the Consolidation Topic of the Financial Accounting Standards Board Accounting Standards Codification, CNX Gas has consolidated the contractor into the Consolidated Financial Statements. At December 31, 2009, the contractor has a carrying value of property, plant and equipment of $13,185 and total assets of $14,687, with related debt of $14,665 and total liabilities of $15,578.

Note 14—Stock-Based Compensation:

CNX Gas adopted the amended CNX Gas Equity Incentive Plan on October 11, 2006. The plan is administered by 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. The plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, cash awards and other stock-based awards. As of December 31, 2009, only stock options and restricted stock units remain outstanding under the plan. The total number 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. In addition to the CNX Gas Equity Incentive Plan, our directors and employees are eligible to receive stock based compensation awards from our affiliate CONSOL Energy. Compensation expense for stock based compensation awards issued by CONSOL Energy directly to CNX Gas directors and employees is recognized based on the fair value of the specific awards. Additionally, CNX Gas is also charged for our proportionate share of CONSOL Energy’s overall stock based compensation expense.

During the year ended December 31, 2009, the plan administrators undertook actions designed to reduce the number of stock options and restricted stock units outstanding under the plan. On March 31, 2009, 24,050 unvested restricted stock units held by an officer and non-employee directors were exchanged for CONSOL Energy restricted stock units. This transaction was accounted for as a cancellation of the existing awards and an issuance of new awards in accordance with the Stock Compensation Topic of the FASB Accounting Standards Codification. The exchange did not have a material impact on the Consolidated Financial Statements. Additionally, no stock option awards were granted under the plan during the year ended December 31, 2009. The plan administrators do not intend to issue any new stock option awards under the plan and intend to limit future restricted stock unit awards to certain non-employee directors who do not also serve on the CONSOL Energy board of directors.

CNX Gas generally recognizes share-based 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. The total stock-based compensation expense was $6,311, $3,378 and $3,260 for the years ended December 31, 2009, 2008 and 2007, respectively. The related deferred tax benefit totaled $2,476, $1,326, and $1,277, respectively, excluding amounts allocated from CONSOL Energy.

79

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Stock Options Awards

As of December 31, 2009, outstanding stock option awards consist of 961,236 employee stock options that vest 25% per year, beginning one year after the grant date and 441,986 employee stock options that vest 100%, three years after the grant date. Additionally, 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 these 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, and 2007, the total fair value of stock options granted was $30 and $151, respectively. There were no stock options awarded during the year ended December 31, 2009.

CNX Gas utilizes 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:

	For the Year Ended December 31, 2008			For the Year Ended December 31, 2007
Weighted Average Fair Value of Grants	$	15.02		$	9.61
Risk Free Interest Rate		4.58	%		4.58	%
Dividend Yield		—			—
Expected Volatility		34.5	%		34.5	%
Expected Forfeiture Rate		2.0	%		2.0	%
Expected Term		4.5 years			4.5 years

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

	Shares		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term (in years)	Aggregate Intrinsic Value (dollars in thousands)
Balance at December 31, 2008	1,440,282		$	20.07
Granted	—			—
Exercised	(11,772	)		17.06
Forfeited	(299	)		16.00
Balance at December 31, 2009	1,428,211		$	20.10	5.85	$	13,482
Vested and expected to vest at December 31, 2009	1,427,916		$	20.10	5.85	$	13,482
Exercisable at December 31, 2009	1,413,461		$	20.01	5.83	$	13,448

Cash received from option exercises for the year ended December 31, 2009 was $200. The excess tax benefit realized for the tax deduction from option exercises totaled $62 for the year ended December 31, 2009. This excess tax benefit is included in cash flows from financing activities in the Consolidated Statement of Cash Flows.

80

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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, 2009 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, 2009. This amount changes based on changes in the fair market value of CNX Gas’ stock. The total intrinsic value of options exercised for the years ended December 31, 2009, 2008 and 2007 was $170, $201 and $286, respectively.

As of December 31, 2009, $37 of total unrecognized compensation cost related to unvested option awards is expected to be recognized over a weighted-average period of 0.79 years.

Restricted Stock Units

Under the Equity Incentive Plan, CNX Gas granted certain employees and certain non-employee directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. Compensation expense for these awards is recognized over the vesting period of the units, or to an employee’s eligible retirement date, if earlier. The fair value of each unit awarded is equivalent to the closing price of a share of CNX Gas stock on the date of the grant. For the years ended December 31, 2009, 2008 and 2007, the total fair value of restricted stock units granted was $120, $600 and $480, respectively.

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

	Shares		Weighted Average Grant Date Fair Value
Non-Vested at December 31, 2008	28,375		$	34.91
Granted	4,637			25.88
Exchanged	(24,050	)		34.73
Vested	(3,510	)		37.76
Non-Vested at December 31, 2009	5,452		$	26.30

The total fair value of restricted stock unit awards that vested during the year was $85.

As of December 31, 2009, $37 of total unrecognized compensation cost related to unvested restricted stock unit awards is expected to be recognized over a weighted-average period of 0.27 years.

Long Term Incentive Compensation

CNX Gas had a long-term incentive program. This program allowed for the award of performance share units (PSUs). A PSU represented 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 was 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 recognized compensation costs over the requisite service period. The basis of the compensation costs was re-valued quarterly. Approximately $8,779 and $2,231 of compensation costs have been recognized for the years ended December 31, 2008 and 2007, respectively. A credit to expense of approximately $1,434 was recognized for the year ended December 31, 2009 as a result of the decline in the value of the expected payout prior to the exchange transaction discussed below.

81

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

During the second quarter of 2009, CNX Gas recognized the effect of an exchange offer that allowed participants in the CNX Gas Long-Term Incentive Program to exchange their unvested performance share units for CONSOL Energy restricted stock units. The excess fair value of the replacement restricted stock units over the original performance stock units resulted in $2,738 of incremental restricted stock compensation expense being immediately recognized. Additionally, a liability of $10,347 for the cash settlement of the CNX Gas performance share units was reclassified into equity due to the issuance of RSUs. As a result of the completed exchange offer there are no outstanding performance share units at December 31, 2009.

Note 15—Accumulated Other Comprehensive Income:

Total comprehensive income, net of tax, consists of the following:

	Change in Fair Value of Cash Flow Hedges			Adjustments for Actuarially Determined Liabilities			Accumulated Other Comprehensive Income
Balance at December 31, 2006	$	1,650		$	760		$	2,410
Net increase in value of cash flow hedges		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 hedges		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
Net increase in value of cash flow hedges		186,824			—			186,824
Reclassification from other comprehensive income to earnings		(239,956	)		—			(239,956	)
Current period adjustment		—			(1,836	)		(1,836	)
Balance at December 31, 2009	$	71,378		$	(1,562	)	$	69,816

The cash flow hedges that CNX Gas holds are disclosed in Note 19. The adjustments for Actuarially Determined Liabilities are disclosed in Note 12.

82

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 16—Supplemental Cash Flow Information:

	For the Years Ended December 31,
	2009			2008			2007
Net Cash provided from operating activities included:
Interest paid	$	6,809		$	7,114		$	5,328
Income Taxes paid	$	14,100		$	63,919		$	19,220
Non-cash investing and financing activities:
Purchase of Property, Plant and Equipment
Change in Assets	$	25,204		$	(32,096	)	$	341
Change in Liabilities	$	25,204		$	(32,096	)	$	341
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	$	(342	)	$	(2,143	)	$	3,563
Change in Liabilities	$	(342	)	$	(2,143	)	$	3,563
Adoption of Accounting for Uncertainty in Income Taxes
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	$	(130	)	$	(1,874	)	$	—
Change in Liabilities	$	(130	)	$	(1,874	)	$	—

83

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 17—Concentration of Credit Risk:

CNX Gas markets natural 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. There were no individual customers with sales constituting 10% or more of outside sales for the year ended December 31, 2009. A table illustrating sales to individual customers constituting 10% or more of outside sales for the years ended December 31, 2008 and 2007, respectively, is as follows:

Year Ended	Customer	Amount For the Year Ended December 31,		Percent of Outside Sales		Accounts Receivable Balance at December 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

Note 18—Fair Value of Financial Instruments:

Effective January 1, 2008, CNX Gas adopted the provision for Fair Value of Financial Assets and Financial Liabilities as required by the Financial Accounting Standards Board Accounting Standards Codification. 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 previously recorded at fair value prior to the adoption.

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

	Fair Value Measurements at December 31, 2009
Description	Quoted Prices in Active Markets for Identical Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Gas Cash Flow Hedges	$	—	$	117,483	$	—

The following methods and assumptions were used to estimate the fair values of financial instruments, for which the fair value option was not elected:

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-term 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.

Long-term debt: The fair values of long-term debt are estimated using discounted cash flow analyses, based on current market rates for instruments with similar cash flows.

84

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The carrying amounts and fair values of financial instruments for which the fair value option was not elected are as follows:

	December 31, 2009						December 31, 2008
	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Cash and cash equivalents	$	1,124		$	1,124		$	1,926		$	1,926
Short-term notes payable	$	(57,850	)	$	(57,850	)	$	(72,700	)	$	(72,700	)
Long-term debt	$	(14,665	)	$	(14,664	)	$	(19,883	)	$	(16,549	)

Note 19—Derivative Instruments:

CNX Gas enters into financial derivative instruments to manage our exposure to commodity price volatility. Our derivatives are accounted for under the Derivatives and Hedging Topic of the Financial Accounting Standards Board Accounting Standards Codification. We measure each derivative instrument at fair value and record it on the balance sheet as either an asset or liability. Changes in the fair value of the 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 the fair values or the 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.

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.

CNX Gas has entered into forward contracts for natural gas to manage the price risk associated with the forecasted revenues from those commodities. The objective of these hedges is to reduce the variability of the cash flows associated with the forecasted revenues from the underlying commodities.

As of December 31, 2009, the total notional amount of the Company’s outstanding natural gas forward contracts was 85.1 billion cubic feet. These forward contracts are forecasted to settle through December 31, 2012 and meet the criteria for cash flow hedge accounting. During the next year, $60,307 of unrealized gain is expected to be reclassified from Other Comprehensive Income and into earnings. No gains or losses have been reclassified into earnings as a result of the discontinuance of cash flow hedges.

85

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

The fair value of CNX Gas’ derivative instruments at December 31, 2009 is as follows:

	Derivatives As of December 31, 2009
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Current Assets—Derivatives	$	99,265
Natural Gas Price Swaps	Other Assets—Derivatives		18,218
Total derivatives designated as hedging instruments		$	117,483

The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2009 is as follows:

Derivatives Cash Flow Hedging Relationship	Amount of (Loss) Recognized in OCI on Derivative 2009			Location of Gain Reclassified from Accumulated OCI into Income	Amount of Gain Reclassified from Accumulated OCI into Income 2009		Location of (Loss) Recognized in Income on Derivative	Amount of (Loss) Recognized in Income on Derivative 2009
Natural Gas Price Swaps	$	(185,862	)	Outside Sales	$	239,956	Outside Sales	$	(962	)
Total	$	(185,862	)		$	239,956		$	(962	)

The fair value of CNX Gas’ derivative instruments at December 31, 2008 is as follows:

	Derivatives As of December 31, 2008
	Balance Sheet Location	Fair Value
Derivative designated as hedging instruments
Natural Gas Price Swaps	Current Assets—Derivatives	$	150,564
Natural Gas Price Swaps	Other Assets—Derivatives		55,945
Total derivatives designated as hedging instruments		$	206,509

The effect of derivative instruments on the Consolidated Statement of Income for the year ended December 31, 2008 is as follows:

Derivatives Cash Flow Hedging Relationship	Amount of (Loss) Recognized in OCI on Derivative 2008			Location of (Loss) Reclassified from Accumulated OCI into Income	Amount of (Loss) Reclassified from Accumulated OCI into Income 2008			Location of Gain Recognized in Income on Derivative	Amount of Gain Recognized in Income on Derivative 2008
Natural Gas Price Swaps	$	(118,652	)	Outside Sales	$	(947	)	Outside Sales	$	952
Total	$	(118,652	)		$	(947	)		$	952

86

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Note 20—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 CONSOL Energy and certain of its affiliates, including CNX Gas Company LLC, in the Circuit Court for the County of Tazewell, Virginia. The lawsuit alleges, among other things, that the defendants have violated the Virginia Antitrust Act in their dealings with GeoMet in southwest Virginia. The complaint, as amended, 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. 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 CNX Gas is cooperating with the Attorney General’s investigation.

The Company is a party to a case filed in 2007 captioned Earl Kennedy (and others) v. CNX Gas and CONSOL Energy in the Court of Common Pleas of Greene County, Pennsylvania. The lawsuit alleges that CNX Gas and CONSOL Energy trespassed and converted gas and other minerals allegedly belonging to the plaintiffs in connection with wells drilled by CNX Gas. The complaint, as amended, seeks injunctive relief, including having CNX Gas be removed from the property, and compensatory damages of $20,000. The suit also sought to overturn existing law as to the ownership of coalbed methane in Pennsylvania, but that claim was dismissed by the court; the plaintiffs are seeking to appeal that dismissal. 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 lawsuit against CNX Gas Company LLC in the Circuit Court of the County of Buchanan for the year 2002; the county has since filed and served three substantially similar cases for years 2003, 2004 and 2005. These cases have been consolidated. The complaint alleges that CNX Gas’ 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, CNX Gas 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. This litigation has been settled on terms that do not materially impact the financial position or the results of operations of CNX Gas.

87

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

In 2004, Yukon Pocahontas Coal Company and others 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 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 2007, production at the Buchanan Mine was suspended after several roof falls damaged some of the ventilation controls inside the mine. Production resumed in March 2008. The incident was covered under our property and business interruption insurance policy, subject to certain deductibles. Business interruption recoveries of $8,000 were recognized as Other Income in the year ended December 31, 2008. The total recoveries have been collected.

At December 31, 2009, 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.

	Amounts Committed		Less Than 1 Year		1-3 Years		3-5 Years		Beyond 5 years
Letters of Credit:
Gas	$	14,913	$	14,913	$	—	$	—	$	—
Total Letters of Credit	$	14,913	$	14,913	$	—	$	—	$	—
Surety Bonds:
Environmental	$	1,500	$	1,500	$	—	$	—	$	—
Other		2,942		2,942		—		—		—
Total Surety Bonds	$	4,442	$	4,442	$	—	$	—	$	—
Other:
Guarantees	$	303,057	$	30,479	$	272,578	$	—		—
Total Guarantees	$	303,057	$	30,479	$	272,578	$	—	$	—
Total Commitments	$	322,412	$	49,834	$	272,578	$	—	$	—

88

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

CNX Gas enters into unconditional purchase obligations to procure major firm transportation, gas drilling services and land purchase obligations. These purchase obligations are not recorded on the Consolidated Balance Sheet. The following is a summary of our purchase obligations at December 31, 2009:

Obligations Due	Amount
Less than 1 year	$	40,086
1 - 3 years		52,120
3 - 5 years		49,934
More than 5 years		303,347
Total Purchase Obligations	$	445,487

Firm transportation expense under these purchase obligations was $21,668, $11,476 and $9,390 for the years ended December 31, 2009, 2008 and 2007 respectively. Expenses related to gas drilling purchase obligations were $585 for the year ended December 31, 2009. There were no transactions related to land purchase obligations for the years presented.

Note 21—Segment Information:

The principal activity of CNX Gas is to produce natural gas for sale primarily to gas wholesalers. 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, 2009, the Central Appalachia segment includes the following operating segments: Virginia Operations, Cardinal States Gathering and Knox Energy. For the year ended December 31, 2009, the Northern Appalachia segment includes the following operating segments: Mountaineer, Nittany and Marcellus. 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.

89

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Reportable segment results for the year ended December 31, 2009 are:

	Central Appalachia		Northern Appalachia			Other			Total Gas		Corporate			Consolidated
Sales—outside	$	536,534	$	89,629		$	1,256		$	627,419	$	—		$	627,419	(A)
Sales—related parties		2,945		234			—			3,179		—			3,179
Sales—royalty interest gas		39,277		1,671			3			40,951		—			40,951
Sales—purchased gas.		4,746		2,294			—			7,040		—			7,040
Other revenue.		3,580		6			568			4,154		701			4,855
Total Revenue and Other Income	$	587,082	$	93,834		$	1,827		$	682,743	$	701		$	683,444
Earnings Before Income Taxes.	$	330,054	$	(28,922	)	$	(1,220	)	$	299,912	$	(36,814	)	$	263,098
Segment assets	$	1,372,124	$	696,826		$	76,495		$	2,145,445	$	25,937		$	2,171,382
Depreciation, depletion and amortization	$	63,304	$	42,617		$	1,330		$	107,251	$	—		$	107,251
Capital expenditures	$	147,647	$	182,494		$	6,306		$	336,447	$	—		$	336,447

(A) No customers accounts for more than 10% of revenue in the year ended December 31, 2009.

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

	Central Appalachia		Northern Appalachia		Other		Total Gas		Corporate			Consolidated
Sales—outside	$	569,051	$	106,668	$	3,074	$	678,793	$	—		$	678,793	(B)
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(C)	$	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

(B) Included in the Central Appalachia segment are sales to customers which comprise over 10% of revenue. These sales consist of of $105,864 to Sempra Energy, $103,093 to B.P. Energy Company and $88,654 to Interstate Gas Supply, Inc.

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

90

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

	Central Appalachia		Northern Appalachia			Other			Total Gas		Corporate			Consolidated
Sales—outside	$	374,663	$	30,070		$	102		$	404,835	$	—		$	404,835	(D)
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(E)	$	240,737	$	(4,438	)	$	(1,802	)	$	234,497	$	(13,858	)	$	220,639
Segment assets(F)	$	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

(D) Included in the Central Appalachia segment are sales to customers which comprise over 10% of revenues. These sales consist 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.

(E) Includes equity in earnings (loss) of unconsolidated affiliates of $2,058 for Central Appalachia.

(F) Includes investments in unconsolidated equity affiliates of $3,408 for Central Appalachia.

Reconciliation of Segment Information to Consolidated Amounts:

Earnings Before Income Taxes:

	For the Years Ended December 31,
	2009			2008			2007
Segment earnings before income taxes for total reportable business segments.	$	299,912		$	420,823		$	234,497
Equity in earnings of Buchanan Generation.		637			328			116
Incentive compensation.		(16,358	)		(7,988	)		(5,659	)
Compensation from restricted stock unit grants, stock option expense and performance share unit expense(G)		(10,912	)		(12,157	)		(5,491	)
Bank fees.		(807	)		(857	)		(1,011	)
Interest income (expense), net.		(7,504	)		(7,420	)		(1,813	)
Operating lease cease-use.		(1,500	)		—			—
Corporate severance.		(370	)		—			—
Earnings before income taxes.	$	263,098		$	392,729		$	220,639

91

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Total Assets:

	December 31,
	2009		2008		2007
Segment assets for total reportable business segments.	$	2,145,445	$	2,067,459	$	1,322,806
Items excluded from segment assets:
Cash and other investments.		1,254		2,008		32,048
Recoverable income taxes.		—		30,302		972
Salary pension asset.		92		—		—
Investment in Buchanan Generation.		24,591		25,204		24,877
Total Consolidated Assets.	$	2,171,382	$	2,124,973	$	1,380,703

(G) Includes amounts allocated from CONSOL Energy.

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

Other Supplemental Information—Supplemental Gas Data (unaudited):

The following information was prepared in accordance with the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).”

Capitalized Costs:

	As of December 31,
	2009			2008
Proved properties	$	152,010		$	121,605
Unproved properties		271,553			220,848
Wells and related equipment		1,171,146			1,019,880
Gathering assets		804,212			740,396
Total Property, Plant and Equipment		2,398,921			2,102,729
Accumulated Depreciation, Depletion and Amortization		(429,966	)		(319,959	)
Net Capitalized Costs	$	1,968,955		$	1,782,770

Costs incurred for property acquisition, exploration and development (*):

	For the Years Ended December 31,
	2009		2008		2007
Property acquisitions and other changes
Proved properties.	$	30,405	$	17,090	$	33,205
Unproved properties.		50,705		119,168		80,313
Development.		181,944		378,119		257,935
Exploration.		46,023		68,495		16,503
Total	$	309,077	$	582,872	$	387,956

(*) Includes costs incurred whether capitalized or expensed.

92

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

Results of Operations for Producing Activities:

	For the Twelve Months Ended December 31,
	2009				2008				2007
	Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Production Revenue.	$	630,598	$	—	$	688,325	$	—	$	416,452	$	2,755
Royalty Interest Gas Revenue.		40,951		—		79,302		—		46,586		294
Purchased Gas Revenue.		7,040		—		8,464		—		7,628		201
Total Revenue.		678,589		—		776,091		—		470,666		3,250
Lifting Costs.		55,285		—		67,653		—		38,721		679
Gathering Costs.		95,687		—		83,752		—		61,798		630
Royalty Interest Gas Costs.		32,423		—		74,041		—		40,011		294
Other Costs.		45,795		—		34,078		—		19,772		646
Purchased Gas Costs.		6,442		—		8,175		—		7,162		165
DD&A.		107,251		—		70,010		—		48,961		294
Total Costs.		342,883		—		337,709		—		216,425		2,708
Pre-tax Operating Income.		335,706		—		438,382		—		254,241		542
Income Taxes.		125,890		—		171,407		—		98,595		210
Results of Operations for Producing Activities excluding Corporate and Interest Costs	$	209,816	$	—	$	266,975	$	—	$	155,646	$	332

The following is production, average sales price and average production costs, excluding ad valorem and severance taxes, per unit of production:

	For the Years Ended December 31,
	2009		2008		2007
Production in million cubic feet.		94,415		76,562		58,249
Average gas sales price before effects of financial settlements (per thousand cubic feet)	$	4.15	$	8.99	$	6.87
Average effects of financial settlements (per thousand cubic feet)	$	2.53	$	—	$	0.33
Average gas sales price including effects of financial settlements (per thousand cubic feet)	$	6.68	$	8.99	$	7.20
Average lifting costs, excluding ad valorem and severance taxes (per thousand cubic feet)	$	0.48	$	0.58	$	0.39

During the years ended December 31, 2009, 2008 and 2007, we drilled 247, 534 and 370 net development wells, respectively. Of these wells drilled in the year ended December 31, 2009 there was one dry well. There were no dry wells in the years ended December 31, 2008 and 2007.

During the years ended December 31, 2009, 2008 and 2007, we drilled 18, 56 and 9 net exploratory wells, respectively. Of the wells drilled in the years ended December 31, 2009 and 2008, there were one and three dry wells, respectively. There were no dry wells in the year ended December 31, 2007.

93

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

At December 31, 2009, there were six development wells in the process of being drilled. Drilling activities are currently in progress to complete the drilling of these wells by the end of March 2010.

At December 31, 2009, there were ten exploratory wells in the process of being drilled. Drilling and evaluation activities will be in process throughout the 2010 period.

CNX Gas is committed to provide 44.1 Bcf of gas under existing contracts or agreements over the course of the next two years. CNX Gas expects to produce sufficient quantities from existing proved developed reserves to satisfy these commitments.

Most of our development wells and proved 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 the number of CNX Gas producing wells, developed acreage and undeveloped acreage at December 31, 2009:

	Gross	Net(1)
Producing Wells (including gob wells)	5,240	3,926
Proved Developed Acreage.	260,327	254,753
Proved Undeveloped Acreage.	56,090	54,298
Unproved Acreage.	3,957,174	3,399,490
Total Acreage.	4,273,591	3,708,541

(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 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.

Proved Oil and Gas Reserve Quantities:

The preparation of our gas reserve estimates are completed in accordance with CNX Gas’ prescribed internal control procedures, which include verification of input data into a gas reserve forecasting and economic evaluation software, as well as multi-functional management review. The technical employee responsible for overseeing the preparation of the reserve estimates is a petroleum engineer. Our 2009 gas reserve results were audited by Netherland Sewell. The technical person primarily responsible for overseeing the audit of our reserves is a certified petroleum engineer. The gas reserve estimates are as follows:

	2009		2008				2007
	Consolidated Operations		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Net Reserve Quantity (MMcfe)
Beginning reserves.	1,422,046		1,339,909		3,584		1,263,293		2,200
Revisions(b)	177,004		(30,828	)	—		(25,036	)	221
Extensions and discoveries(c)	406,756		182,701		—		145,834		1,484
Production.	(94,415	)	(76,562	)	—		(57,928	)	(321	)
Acquisition of remaining interest in equity affiliate.	—		3,584		(3,584	)	—		—
Purchases of reserves in-place.	—		3,242		—		13,746		—
Sale of reserves in-place.	—		—		—		—		—
Ending reserves(a)	1,911,391		1,422,046		—		1,339,909		3,584

94

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(a) Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission (SEC) 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. 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.

(b) Revisions are primarily due to efficiencies in operations which resulted in a reduction of operating costs, a comprehensive look into reservoir characterization and well performance.

(c) Extensions and discoveries are due to the addition of our Marcellus Shale acreage and approvals from the Oil & Gas Board in Virginia to drill and complete wells on tighter spacing. Extensions and discoveries also include 120,933 MMcfe as a result of initially applying the amendments of ASC 932 in ASU 2010-03 related to capturing proved undeveloped locations more than one location away if reliable technology can be demonstrated.

	2009			2008			2007
	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe	All Products	Natural Gas mmcf	Oil mmcfe
Proved developed reserves (consolidated entities only)
Beginning of year.	783,290	783,010	280	667,726	667,443	283	609,700	609,538	162
End of year.	1,040,257	1,039,052	1,205	783,290	783,010	280	667,726	667,443	283
Proved undeveloped reserves (consolidated entities only)
Beginning of year.	638,756	638,756	—	672,183	672,183	—	653,593	653,593	—
End of year.	871,134	871,134	—	638,756	638,756	—	672,183	672,183	—

	For the Year Ended December 31, 2009
Proved Undeveloped Reserves (MMcfe)
Beginning proved undeveloped reserves.	638,756
Undeveloped reserves transferred to developed(a)	(118,145	)
Revisions.	27,601
Extension and discoveries.	322,922
Ending proved undeveloped reserves(b)	871,134

(a) During 2009, various exploration and development drilling and evaluations were completed. Approximately, $45,326 of capital was spent in the year ended December 31, 2009 related to undeveloped reserves that were transferred to developed.

95

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

(b) Included in proved undeveloped reserves at December 31, 2009 are approximately 120,000 MMcfe of reserves that have been reported for more than five years that relate specifically to CONSOL Energy’s Buchanan Mine. These undeveloped reserves will be developed in order to de-gas the mine ahead of longwall mining.

The following table represents the capitalized exploratory well cost activity as indicated:

	December 31, 2009
Costs pending the determination of proved reserves at December 31, 2009(a)
Less than one year.	$	156
More than one year but less than five years.		5,454
More than five years.		2,627
Total.	$	8,237

(a) Costs held in exploratory for more than one year represent exploration wells away from existing infrastructure. The additional planned exploration expenditures will allow us to invest in infrastructure to support these fields.

	For the Years Ended December 31,
	2009		2008		2007
Costs reclassified to wells, equipment and facilities based on the determination of proved reserves.	$	52,332	$	1,887	$	402
Costs expensed due to determination of dry hole or abandonment of project.	$	8,194	$	1,197	$	—

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 the Financial Accounting Standards Board’s Accounting Standards Update No. 2010-03, “Extractive Activities—Oil and Gas (Topic 932).” This topic requires the standardized measure of discounted future net cash flows to be based on the average, first-day-of-the-month price for the year ended December 31, 2009. Because prices used in the calculation are average prices for that year, the standardized measure could vary significantly from year to year based on the market conditions that occurred.

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 a different price and cost assumptions.

96

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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,
	2009			2008			2007
Future Cash Flows:
Revenues	$	7,975,195		$	8,856,817		$	9,509,665
Production costs		(3,123,532	)		(3,525,902	)		(3,004,619	)
Development costs		(995,569	)		(793,592	)		(636,436	)
Income tax expense		(1,465,075	)		(1,713,713	)		(2,259,415	)
Future Net Cash Flows		2,391,019			2,823,610			3,609,195
Discounted to present value at a 10% annual rate		(1,496,668	)		(1,605,176	)		(2,219,655	)
Total standardized measure of discounted net cash flows(a)	$	894,351		$	1,218,434		$	1,389,540

(a) The estimated effect on the PV-10 calculation of initially applying the amendments of ASC 932 in ASU 2010-03 was $39,059.

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

	December 31,
	2009			2008						2007
	Consolidated Operations			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Balance at beginning of period	$	1,218,434		$	1,384,983		$	4,557		$	933,186		$	1,705
Net changes in sales prices and production costs		(333,130	)		(676,358	)		—			1,681,550			7,356
Sales net of production costs		(335,706	)		(438,382	)		—			(207,688	)		(1,122	)
Net change due to revisions in quantity estimates		189,583			(63,547	)		—			479,618			5,959
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		181,944			378,119			—			257,935			—
Difference in previously estimated development costs compared to actual costs incurred during the period		(3,282	)		(136,742	)		—			(87,408	)		—
Changes in estimated future development costs		(380,639	)		(398,534	)		—			(254,635	)		(214	)
Net change in future income taxes		248,639			545,702			—			(754,209	)		(4,673	)
Accretion of discount and other		108,508			614,478			—			(666,206	)		(4,454	)
Total discounted cash flow at end of period	$	894,351		$	1,218,434		$	—		$	1,384,983		$	4,557

97

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands, except per share data)

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

	Three Months Ended
	March 31, 2009		June 30, 2009		September 30, 2009		December 31, 2009
Total Revenue and Other Income	$	178,384	$	161,608	$	165,653	$	177,799
Total Costs and Expense	$	89,303	$	108,806	$	108,227	$	115,047
Total Earnings Before Income Tax	$	89,344	$	53,123	$	57,664	$	62,967
Net Income Attributable to CNX Gas Shareholders	$	54,904	$	32,977	$	35,470	$	41,111
Earnings per Share
Basic	$	0.36	$	0.22	$	0.23	$	0.28
Diluted	$	0.36	$	0.22	$	0.23	$	0.28
Weighted Average Shares Outstanding
Basic		150,971,679		150,974,581		150,977,117		150,985,412
Diluted		151,232,901		151,328,744		151,372,672		151,397,310

	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	$	79,837	$	101,640	$	101,684	$	114,201
Total Earnings Before Income Tax	$	80,917	$	104,386	$	115,575	$	91,851
Net Income Attributable to CNX Gas Shareholders	$	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
Diluted		151,324,786		151,438,737		151,292,158		151,240,785

98

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 year ended December 31, 2007, 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 year ended December 31, 2007 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 year. During the year ended December 31, 2007, 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 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, 2009. 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, 2009. The effectiveness of CNX Gas’ internal control over financial reporting as of December 31, 2009 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, 2009, 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, 2009, 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 sheets of CNX Gas Corporation (and Subsidiaries) as of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders’ equity, and cash flows for the years then ended and our report dated February 9, 2010 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Pittsburgh, PA

February 9, 2010

Item 9B. Other Information.

None.

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PART III

Item 10. Directors and Executive Officers of the Registrant.

The information required by this Item is incorporated herein by reference to the information under the captions “Proposals for Consideration at the Annual Meeting of Stockholders—Proposal #1—Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “General Information—The Board of Directors and Its Committees—Corporate Governance Web Page and Available Documents,” and “General Information—The Board of Directors and Its Committees—Audit Committee” in the Proxy Statement for the annual meeting of shareholders to be held on May 4, 2010 (the “Proxy Statement”).

Executive Officers of CNX Gas Corporation

The following is a list of CNX Gas executive officers, their ages as of February 9, 2010 and their positions and offices held with CNX Gas.

Name	Age	Position
J. Brett Harvey	59	Chairman of the Board and Chief Executive Officer
Nicholas J. DeIuliis	41	President and Chief Operating Officer
William J. Lyons	61	Executive Vice President and Chief Financial Officer
P. Jerome Richey	60	Executive Vice President Corporate Affairs and Chief Legal Officer
Robert P. King	57	Executive Vice President Business Advancement and Support Services
Robert F. Pusateri	59	Executive Vice President Energy Sales and Transportation Services

J. Brett Harvey has 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. DeIuliis was 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. Lyons has 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, 2005 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. King became 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—

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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.

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,” “General Information—The Board of Directors and its Committees—Compensation Committee Interlocks and Insider Participation,” and “General Information—The Board of Directors and its Committees—Audit Committee” 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 “Executive Compensation and Stock Option Information—Equity Compensation Plan Information,” and “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 Party Transactions—Related Party Transactions” and “General Information—The Board of Directors and its Committees—Director Independence” 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 9th day of February 2010.

CNX GAS CORPORATION
By:	/s/    J. BRETT HARVEY
	J. Brett Harvey Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 9th day of February 2010, 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	Chief Financial Officer and Executive Vice President (Principal Financial and Accounting Officer)
/s/    RAJ K. GUPTA         Raj K. Gupta	Director
/s/    PHILIP W. BAXTER         Philip W. Baxter	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	Third Amended and Restated Bylaws of CNX Gas Corporation, as amended(23)
4.1	Form of stock certificate(1)
10.1	Form of Change in Control Agreement for DeIuliis, Albert and Onifer(22)(29)*
10.2	Form of Change in Control Agreement for Johnson(29)*
10.3	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)
10.4	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 Gas Subsidiary (as defined therein)(3)
10.5	Amendment No. 1 to the Master Cooperation and Safety Agreement dated as of May 30, 2008(20)
10.6	Tax Sharing Agreement dated August 1, 2005 between CONSOL Energy Inc. and CNX Gas Corporation(3)
10.7	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)
10.8	Intercompany Revolving Credit Agreement between CONSOL Energy Inc. and CNX Gas Corporation(3)
10.9	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)
10.10	Credit Agreement dated October 7, 2005 between CNX Gas Corporation, certain of its subsidiaries and the Lender parties thereto(4)
10.11	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)
10.12	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)
10.13	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)
10.14	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)
10.15	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)
10.16	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)
10.17	Supplemental Indenture No. 11, dated as of June 3, 2008, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(28)

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10.18	Supplemental Indenture No. 12, dated as of July 28, 2008, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(28)
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(29)*
10.24	Form of Award Agreements under CNX Gas Corporation Equity Incentive Plan, as amended(1)*
10.25	Summary description of CNX Gas 2007 Short-term incentive program(15)*
10.26	Summary description of the base compensation and short-term incentive opportunities for the executive officers of CNX Gas for 2007(16)*
10.27	Schedule of Compensation of Non-Employee Directors, effective August 2007(25)*
10.28	2008 CNX Gas Long-Term Incentive Program and the Form of Award Agreement thereunder(17)*
10.29	Summary of CNX Gas 2008 Short-term Incentive Program(18)
10.30	CNX Gas Corporation Directors Deferred Fee Plan effective January 1, 2008(19)
10.31	Separation Agreement and General Release dated as of April 30, 2008 between Mark D. Gibbons and CNX Gas Corporation(21)
10.32	Election Form to Exchange CNX Gas Performance Share Units into CONSOL Energy Inc. Restricted Stock Units (Private Placement)(24)
10.33	Form of Indemnification Agreement for Directors and Executive Officers(25)
10.34	Form of Election and Restricted Stock Unit Award Agreement (Exchange Offer)(26)
10.35	CONSOL Energy Inc. Supplemental Retirement Plan, as amended and restated(27)
21	Subsidiaries of CNX Gas Corporation
23.1	Consent of Ernst & Young LLP
23.2	Consent of PricewaterhouseCoopers LLP
23.3	Consent of Netherland, Sewell and Associates, Inc.
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
99	Engineers’ Audit Letter

107

101 Interactive Data File (Form 10-K for the year ended December 31, 2009 furnished in XBRL)

(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-K filed by CNX Gas on February 15, 2008

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

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

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

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

(22) 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.

(23) Incorporated by reference from the Current Report on Form 8-K filed by CNX Gas on June 23, 2009

(24) Incorporated by reference from the Quarterly Report on Form 10-Q filed by CNX Gas on April 27, 2009

(25) Incorporated by reference from the Quarterly Report on Form 10-Q filed by CNX Gas on August 3, 2009

(26) Incorporated by reference to Exhibit 99.1 to Amendment No. 1 to Form S-4 of CONSOL Energy Inc. (file no. 333-157894) filed on June 26, 2009

(27) Incorporated by reference to Exhibit 10.1 to Form 8-K filed by CONSOL Energy, Inc. on September 11, 2009

(28) Incorporated by reference to Form 10-Q filed by CONSOL Energy Inc. on August 5, 2008.

(29) Incorporated by reference to Form 10-K filed by CNX Gas on February 17, 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.

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