10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934.

For the fiscal year ended December 31, 2005;

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.)

4000 Brownsville Road

South Park, PA 15129-9545

(412) 854-6719

(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  ¨    No  x

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  x

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  ¨    No  x

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.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

Large accelerated filer  ¨ Accelerated filer  ¨ Non-accelerated filer  x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act).    Yes  ¨    No  x

The aggregate market value of voting stock held by nonaffiliates of the registrant as of January 31, 2006, based on the closing price of the common stock on the New York Stock Exchange on such date ($24.06 per share), was $669,040,149. For purposes of determining this amount, affiliates include directors and executive officers, who in the aggregate beneficially own 125,912 shares, and CONSOL Energy Inc., which beneficially owns 122,896,667 shares.

The number of shares outstanding of the registrant’s common stock as of January 31, 2006 is 150,833,334 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CNX Gas Corporation’s Proxy Statement for the Annual Meeting of Stockholders to be held on April 28, 2006, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	4
Item 1A.	Risk Factors	26
Item 2.	Properties	34
Item 3.	Legal Proceedings	34
Item 4.	Submission of Matters to a Vote of Security Holders	35
	Executive Officers of CNX Gas Corporation	100
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities	36
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	60
Item 8.	Financial Statements and Supplementary Data	62
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures	98
Item 9A.	Controls and Procedures	98
Item 9B.	Other Information	99
	PART III
Item 10.	Directors and Executive Officers of the Registrant	100
Item 11.	Executive Compensation	101
Item 12.	Security Ownership of Certain Beneficial Owners and Management	101
Item 13.	Certain Relationships and Related Transactions	101
Item 14.	Principal Accounting Fees and Services	101
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	102
SIGNATURES		103

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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;

• our cash flow and liquidity;

• declines in the prices we receive for our gas affecting our operating results and cash flow;

• uncertainties in estimating our gas reserves;

• replacing our gas reserves;

• uncertainties in exploring for and producing gas;

• our inability to obtain additional financing necessary in order to fund our operations, capital expenditures and to meet our other obligations;

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

• competition in the gas industry;

• our inability to retain and attract key personnel;

• our joint venture arrangements;

• the effects of government regulation and permitting and other legal requirements;

• costs associated with perfecting title for gas rights in some of our properties;

• our need to use unproven technologies to extract coalbed methane in some properties;

• our relationships and arrangements with CONSOL Energy; and

• other factors discussed under “Risk Factors.”

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PART I

ITEM 1. BUSINESS

General

We are engaged in the exploration, development and production of natural gas in the Appalachian Basin. We are also a leading developer of coalbed methane (CBM). CONSOL Energy Inc. (CONSOL Energy) owns 81.5% of our outstanding common stock. We have acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other Western Basins. As of December 31, 2005, we had 1,130.4 Bcfe of net proved reserves, including our portion of equity affiliates, with a PV-10 value of $3,051.9 million and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of approximately $1,870.8 million. Our proved reserves are approximately 99% CBM and 49% proved developed. We believe that we are the second largest gas producer in the Appalachian Basin with net sales of 48.4 Bcf for the twelve months ended December 31, 2005. Our proved reserves are long-lived with a reserve life index of 22.5 years.

We have the development rights to approximately 704,000 net CBM acres throughout the Appalachian Basin. Presently, 97% of our proved reserves are located in Central Appalachia where we have the right to develop approximately 296,000 net CBM acres. As of December 31, 2005, we have developed 41% of our Central Appalachian CBM acreage. In Northern Appalachia, we have the rights to develop approximately 408,000 net CBM acres of which only 9% are currently classified as developed. Our undeveloped CBM acreage contains over 2,000 drilling locations. In addition to our CBM activities, we participate in two joint ventures that target conventional development opportunities on approximately 399,000 gross acres throughout the Appalachian Basin. Our conventional acreage position is 99% undeveloped and contains over 6,000 potential drilling locations.

We began extracting CBM in the early 1980s 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. 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.

Except as otherwise noted or unless the context otherwise requires, (i) the information in this Annual Report gives effect to the contribution to CNX Gas of the CONSOL Energy gas business effective as of August 8, 2005, (ii) CNX Gas refers, with respect to any date prior to the effective date of that contribution, to the CONSOL Energy gas business and, with respect to any date on or subsequent to the effective date of the contribution, to CNX Gas and our subsidiaries, (iii) “CONSOL Energy” refers to CONSOL Energy Inc. and its subsidiaries other than CNX Gas and the companies which conducted CONSOL Energy’s gas business, and (iv) reserve and operating data are as of December 31, 2005, unless otherwise indicated. The estimates of our proved reserves as of December 31, 2004 and 2003 included in this Annual Report are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. The estimates of our proved reserves as of December 31, 2005 included in this Annual Report are based on a reserve report prepared by Schlumberger Data and Consulting Services. With the exception of “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and related financial statements, we discuss production, per unit revenue and per unit costs net of any royalty owners’ interest. We use the word “net” to indicate when a number does not include the royalty owners’ interest. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, for the twelve months ended December 31, 2005, 2004 and 2003 is included in Note 19 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

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History of CNX Gas

We began extracting CBM from coal seams in Virginia in the early 1980s as part of CONSOL Energy’s operations. CBM was extracted from the Pocahontas #3 seam in order to reduce the amount of gas in the coal seam prior to mining to enhance safety. Typically, the gas was vented to the atmosphere.

In 1990, CONSOL Energy created a joint venture with Conoco Inc. (Conoco) to produce CBM that qualified for certain preferential tax treatment. Under an operating arrangement, CONSOL Energy operated gas wells and gathering facilities in which Conoco had an ownership interest. In 1993, CONSOL Energy acquired the assets of Island Creek Coal Company in Virginia, including an interest in CBM and gathering assets, from Occidental Petroleum (Occidental). The related gas assets acquired from Occidental were sold to MCN Energy Group Inc. (MCN) in 1995, although CONSOL Energy continued to operate gas wells in the area for MCN under an operating agreement.

Between 2000 and 2001, CONSOL Energy reacquired the assets of MCN and acquired the interests of our joint venture partner, Conoco, to consolidate our interest in Central Appalachia. This created the core of our business.

In 2002, Buchanan Generation, LLC, a joint venture between CONSOL Energy and Allegheny Energy Supply Company, LLC (Allegheny Energy), completed construction of an 88-megawatt electric generating peaking facility. The facility is located near our gas production complex in Virginia and operates on gas produced by our Central Appalachian gas operations.

Recent Events

CNX Gas Corporation’s registration statement on Form S-1 (SEC File No. 333-127483) was declared effective by the Securities and Exchange Commission (“SEC”) on January 18, 2006. On January 19, 2006, our common stock commenced trading on the New York Stock Exchange (“NYSE”) under the symbol “CXG.”

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 New York Stock Exchange under the symbol CNX. Those companies include: CNX Gas Company LLC; Cardinal States Gathering Company (“CSGC”); Coalfield Pipeline Company; Knox Energy LLC; a joint venture with Kelly Oil and certain other entities; and Buchanan Generation, LLC. These are the companies primarily responsible for the exploration, production, transportation and sales of our gas, with the exception of Buchanan Generation LLC. Buchanan Generation LLC uses our gas to generate electricity from a generating facility located near our Virginia gas field. CONSOL Energy owns 81.5% of the outstanding common stock of CNX Gas.

As part of CONSOL Energy, our gas business was unique among gas producers because a substantial portion of our gas production was associated with mining activity in the same coal horizons from which gas could be extracted. For example, in 1999, more than 47% of our total gas production was attributable to mining activities. Currently, about 17% of our total gas production is attributable to mining activities, with the remainder of the gas produced not attributable to active mining activities, reflecting our investment in additional coalbed frac wells during the past five years.

We undertook the separation of our gas business from CONSOL Energy to achieve the following objectives:

• achieve a higher valuation for our business than we believe could be achieved if we remained part of CONSOL Energy;

• allow us to use our own capital and borrowing capability, rather than compete for capital with the mining business, to more rapidly expand gas production from our proven reserves and unproven acreages; and

• allow our key managers to focus solely on the growth and operation of CNX Gas.

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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. There were however, certain other property interests that were retained by CONSOL Energy and not conveyed to CNX Gas. These retained assets, which included, for example, assets associated with gas well plugging, had an aggregate book value of $6.6 million and are not material to the business and operations of CNX Gas. 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 with CONSOL Energy under which they will provide us certain corporate staff services and coordinate our tax filings.

We have made every effort to preserve the synergies that exist between CONSOL Energy’s mining activities and our gas production activities. Additionally, the master cooperation and safety agreement between us and CONSOL Energy will ensure that we continue to have access to gob gas and gas produced from horizontal wells drilled from inside CONSOL Energy’s mines. These additional sources of gas enhance our overall recovery rates for CBM. Similar circumstances exist in the production of CBM in our Northern Appalachia area, where comparable mining techniques are employed.

Coordination with Mining Activities

Approximately 17% of our current gas production is produced as a consequence of coal extraction by CONSOL Energy (not including another approximately 16% of our production that is associated with previously mined areas). It is essential that gas liberated by the mining process be captured and 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, an annual drilling program is prepared 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 drilling and the number of wells proposed to be drilled in the following calendar year, and (ii) the approximate location of all systems proposed to be installed by CNX Gas.

Other Assets

In addition to our production assets, we own certain mid-stream assets that are an integral part of our gas operations. Among the most important is our gathering system. Our operations in Central Appalachia built separate gathering systems to deliver gas to market. Each gathering system begins at the individual wellhead. Gas from wells is transported to market in each case by CSGC’s major gathering system. CSGC operates a 50-mile, 16-inch gathering system capable of transporting 100 mmcf of gas per day and a 30-mile, 20-inch gathering system capable of transporting 150 mmcf of gas per day. Each of these systems connects to a major interstate pipeline in West Virginia. The aggregate capacity of 250 mmcf per day in these systems is more than the current daily production from our Central Appalachia operations, allowing us to expand with economies of scale.

We also own various processing plants in Virginia and in Pennsylvania that remove contaminants from certain types of CBM gas in order to meet interstate pipeline standards. These plants allow us to sell gas that might otherwise be unsaleable.

Through a joint venture with Allegheny Energy, we own a 50% interest in an 88-megawatt, gas-fired electric generating facility in Virginia near our gas production facilities. This facility, which is used to meet peak load demands for electricity, uses the CBM that we produce. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for our gas of up to 22 mmcf per day.

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Currently all of our Central Appalachia production is transported to market on the Columbia interstate pipeline system. We expect to create transportation alternatives through certain transportation agreements with a second interstate pipeline operator, East Tennessee Natural Gas, LLC (ETNG), a subsidiary of Duke Energy. These agreements require the construction by ETNG of an approximately 32-mile lateral pipeline to our gas field in Virginia from ETNG’s major transportation pipeline to the south. Called Jewell Ridge, this proposed lateral pipeline currently is expected to be in service in the second half of 2006. In connection with the construction of the Jewell Ridge lateral, we will enter into a 15 year firm transportation agreement with ETNG at pre-determined fixed rates. We anticipate that the present value of our payments under this firm transportation agreement will be approximately $67 million. In addition to providing us with transportation flexibility, the Jewell Ridge Lateral will provide access for our product to alternate and growing natural gas markets in the southeastern United States.

Gas Operations

We 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 than those incurred by producers that operate in deeper, less defined formations.

Nearly all of our gas production currently is from operations in Central Appalachia. In this region, we operated 1,862 net wells, 952 miles of gathering lines and various compression stations at December 31, 2005. Our Central Appalachia operations have the right to extract gas from approximately 296,000 net CBM acres. At December 31, 2005, we had 1,095.2 Bcfe of net proved reserves in Central Appalachia, of which 47.9% is developed. Our average daily net production for the month of December 2005 in this region was 130.9 mmcf per day.

We have been developing gas production in Northern Appalachia by gathering gob gas at CONSOL Energy mines in the area and by drilling vertical to horizontal wells in un-mined coal seams. In this region, we operated 133 wells at December 31, 2005 and our average daily net production for the month of December 2005 was approximately 7.6 mmcf per day. At December 31, 2005, we had 32.5 Bcf of net proved reserves in Northern Appalachia, of which approximately 78.4% is developed. We expect to expand production of gas in this area by drilling additional production wells into the coal seams that CONSOL Energy owns or controls.

We have also been developing gas production in the Tennessee area through a 50% joint venture. In this area, we operated 34.5 wells at December 31, 2005 and our portion of average daily net production for the month of December 2005 was approximately 0.2 mmcf per day. At December 31, 2005, our portion of proved net gas reserves for this area was 2.7 Bcfe, of which 100% were developed.

Areas of Operation

We operate in these principal areas of the Appalachian Basin:

Central Appalachia

We have the right to extract CBM in this region from approximately 296,000 net CBM acres, which contain most of the over 400 million tons of proved coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. 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 contains on average 400 to 600 cubic feet of gas per ton of coal in place. In addition, there

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are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

We coordinate some of our CBM extraction with the subsurface coal mining of CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam 5 to 10 years ahead of the planned mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” Presently, frac wells account for approximately 67% of our daily 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 efficacy 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 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 created in the cavity created by the extraction of the coal. When the coal is removed, the rock above, which includes as many as 50 thinner, unminable coal seams, collapses into the void. These seams become extensively fractured and release substantial volumes of gas as they collapse. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 32% of our gas production comes in the form of gob gas (16% active gob and 16% sealed gob). CONSOL Energy pays for the drilling of our gob wells in most instances.

Recently, we began drilling 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 desorbtion of CBM from the coal seam. As of December 31, 2005, we have drilled 10 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. The results from these wells are encouraging and suggest that a more efficient recovery of gas in place is possible ahead of mining operations. The production rates from frac wells have not been adversely impacted by the introduction of nearby horizontal wellbores in the coal seam. In fact, production at offsetting frac wells has actually increased due, we believe, to the further reduction in pressure within the coal seam caused by the horizontal wells. We intend to increase our use of the horizontal wells drilled within an active mine in our future development plans. In-mine horizontal wells account for about 1% of current daily production.

Northern Appalachia

We have the right to extract CBM in this region from approximately 408,000 net CBM acres, which contain most of the over 2.7 billion tons of proved 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 seam which is the main coal seam mined by CONSOL Energy in this region. 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 about 100 to 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to over 7,000 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

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Due to the significant geological differences between the Pittsburgh #8 seam in Northern Appalachia and the Pocahontas #3 seam in Central Appalachia, we have found that alternative extraction techniques are more effective than frac wells. Instead, we utilize a well design that relies on the application of vertical-to-horizontal drilling techniques that we developed. This well design includes a vertical wellbore that is intersected by a second well that has up to three horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending 3,000 to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of surface area of the coal seam allowing for the migration of water and CBM from the coal seam. This design creates up to 15,000 feet of total productive wellbore and are spaced in up to one square mile 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.

Tennessee

We are exploring for conventional natural gas in various formations at depths up to 6,500 feet with a joint venture partner and through a farm-out arrangement on approximately 208,000 gross leasehold acres in this region. At December 31, 2005, we had 2.7 Bcfe of proved reserves in this area. As of December 31, 2005, we have 40 gross wells that are operating. In total, we have an inventory of approximately 5,000 conventional gas drilling locations on this acreage, none of which are proved undeveloped locations.

Illinois and Other Western Basins

We have acquired all of CONSOL Energy’s rights associated with CBM from approximately over 1.4 billion tons of proved coal reserves owned or controlled by CONSOL Energy in these regions. We do not currently have any operations in these regions. We have not fully evaluated our ability to produce CBM in these regions and we may need to acquire additional rights from holders of real estate interests in order to obtain the rights needed to extract and produce CBM.

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The table below sets forth the states and counties in each of our principal operating areas where our properties reside. We have excluded the Illinois and Other Western Basins area from the table below, since we have not yet conducted our own operations in that area.

Central Appalachia Region

Kentucky
Breathitt	Floyd	Johnson
Knott	Letcher	Magoffin
Pike
Virginia
Bland	Buchanan	Carroll
Culpeper	Dickenson	Russell
Tazewell	Washington	Wythe
West Virginia
Braxton	Clay	Lewis
Logan	McDowell	Mercer
Mingo	Nicholas	Pocahontas
Raleigh	Randolph	Upshur
Webster	Wyoming
Northern Appalachia Region
Maryland
Baltimore
Ohio
Athens	Belmont	Carroll
Columbiana	Gallia	Guernsey
Harrison	Highland	Jefferson
Meigs	Monroe	Morgan
Muskingum	Noble	Perry
Vinton	Washington
Pennsylvania
Allegheny	Armstrong	Beaver
Butler	Clearfield	Fayette
Greene	Indiana	Jefferson
Somerset	Washington	Westmoreland
West Virginia
Barbour	Brooke	Doddridge
Grant	Harrison	Marion
Marshall	Monongalia	Ohio
Taylor	Tucker	Wetzel
Tennessee Region
Claiborne	Morgan	Campbell
Scott	Roane	Anderson
New York Region
Allegany	Steuben

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Summary of Appalachian Basin Properties as of December 31, 2005

	Central Appalachia		Northern Appalachia		Tennessee		New York	Total
Estimated Net Proved Reserves (Bcfe)	1,095.2		32.5		2.7		—	1,130.4
Percent Developed (1)	47.9	%	78.4	%	100	%	—	48.8	%
Net Producing Wells	1,862		133		34.5		—	2,029.5
No. of Potential Drill Sites Available	2,900		722		5,053		—	8,675
	Central Appalachia		Northern Appalachia		Tennessee		New York	Total
Net Proved Developed CBM Acres	120,720		36,311		—		—	157,031
Net Proved Undeveloped CBM Acres	33,320		5,760		—		—	39,080
Net Unproved CBM Acres (2)	141,960		365,760		—		—	507,720
Total Net CBM Acres	296,000		407,831		—		—	703,831
Gross Proved Developed Conventional Acres	2,780		—		2,680		—	5,460
Gross Proved Undeveloped Conventional Acres	—		—		—		—	—
Gross Unproved Conventional Acres	149,820		—		205,204		38,720	393,744
Total Gross Conventional Acres	152,600		—		207,884		38,720	399,204

(1) We estimate the cost to fully develop our proved undeveloped reserves excluding abandonment is $361.1 million (non-discounted and in 2005 dollars).

(2) CBM extraction rights associated with CONSOL Energy owned or controlled coal.

Our inventory of conventional drilling sites was determined by dividing our acreage in each area by the well spacing generally used in that area. In Tennessee, wells are commonly drilled on 40 acre units and in Central Appalachia, wells are drilled on an average of 110 acre spacing. The inventory of CBM locations was determined in a detailed evaluation of our Northern Appalachia and Central Appalachia reserves by Schlumberger Data & Consulting Services. The total CBM drilling site inventory reflects the sum of 80-acre and 60-acre vertical development well locations, 40-acre infill well locations and 640-acre horizontal well locations identified in the study. The inventory of drilling sites excludes a number of potential locations in New York, Illinois and other Western Basins because we are not yet active in those areas.

We own all of the properties reflected in the table above by deed or by lease, other than the properties included in the production joint ventures described in the table below.

Summary of Production Partners and Joint Venture Interests as of December 31, 2005

Area	Type	Production Partners and Joint Venture Interests	Acreage	Working Interest	How Acquired
Central Appalachia	Conventional	Columbia Natural Resources, LLC	152,600 Gross Conventional Acres	50%	Contributed by CONSOL Energy
Northern Appalachia	N/A	None	N/A	N/A	N/A
Tennessee	Conventional	New River Energy, LLC (1)	207,884 Gross Conventional Acres	50%	Acquired through lease jointly with New River Energy, LLC
New York	Conventional	Kelly Oil and Gas, Inc. Excelsior Exploration Corporation KWR Ventures, LLC Ceja Corporation	38,720 Gross Conventional Acres	25%	By purchase of working interest

(1) New River Energy, LLC owns 50% of Knox Energy, LLC. We own the remaining 50%. A similar arrangement is in place with respect to Coalfield Pipeline Company which owns and operates the pipeline that gathers the Knox Energy, LLC gas for transportation to the sales pipeline.

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Recent Drilling Activity (net wells)

	2005		2004		2003
CBM (frac, gob, horizontal)		240		228		256
Conventional		—		12		24
Total Wells		240		240		280
Completion %		100		100		99
Total Capital Expenditures (in thousands)	$	110,752	$	89,753	$	83,869

Drilling

The total average daily gross rate of production controlled by us during the twelve months ended December 31, 2005, was 156.0 mmcf. During the twelve months ended December 31, 2005, December 31, 2004 and December 31, 2003, we drilled in the aggregate 225, 235 and 251 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 225, 228 and 244 wells, respectively. As of December 31, 2005, we have not had any dry development wells. The following table illustrates the wells referenced above by geographic region:

Development Wells

	Twelve Months Ended December 31,
	2005		2004		2003
	Gross	Net	Gross	Net	Gross	Net
Central Appalachia	206	206	229	222	237	237
Northern Appalachia	19	19	6	6	—	—
Tennessee	—	—	—	—	14	7
Total	225	225	235	228	251	244

During the twelve months ended December 31, 2005, 2004 and 2003, we drilled in the aggregate 15, 17 and 52 exploratory wells, respectively. The net number of wells for those periods was 15, 12 and 36 respectively. The following table illustrates the exploratory wells by geographic region:

Exploratory Wells

	Gross			Net
2005	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	2	—	—	2	—	—
Northern Appalachia	13	—	—	13	—	—
Tennessee	—	—	—	—	—	—
	15	—	—	15	—	—
	Gross			Net
2004	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	—	—	—	—	—	—
Northern Appalachia	7	—	—	7	—	—
Tennessee	10	—	—	5	—	—
	17	—	—	12	—	—

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	Gross			Net
2003	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	17	—	2	14	—	2
Northern Appalachia	3	—	4	3	—	4
Tennessee	16	3	7	8	1.5	3.5
	36	3	13	25	1.5	9.5

Summary of Other Operating Data

Production

The following table sets forth CNX Gas’ net sales volume produced for the periods indicated, including our portion of equity affiliates.

	Twelve Months Ended December 31,
	2005	2004	2003
Total Produced (mmcf)	48,390	48,556	44,459

Average Sales Prices and Lifting Costs

The following table sets forth the average sales price, net of hedging transactions, and the average lifting cost, including our portion of equity interests, for all of our gas production for the periods indicated. Lifting cost is the cost of raising gas to the gathering system and does not include depreciation, depletion or amortization.

	Twelve Months Ended December 31,
	2005		2004		2003
Average Gas Sales Price Including Effects of Financial Settlements (per mcf)	$	6.08	$	5.09	$	4.14
Average Lifting Cost (per mcf)	$	0.57	$	0.50	$	0.48

Productive Wells and Acreage

The following table sets forth, at December 31, 2005, the number of CNX Gas’ producing wells, developed acreage and undeveloped acreage:

	Gross	Net
Producing Wells	2,073	2,030
Proved Developed Acreage	162,491	159,761
Proved Undeveloped Acreage	39,080	39,080
Unproven Acreage	901,464	694,912

We drilled 225 development wells in the twelve months ended December 31, 2005, of which 51 wells were in process at December 31, 2005. Most of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

For 2006, the Board of Directors has approved a capital budget of $190 million. Plans include the drilling of 290 wells, including 215 frac wells in Central Appalachia, 23 vertical-to-horizontal wells in Northern Appalachia, and 47 conventional wells in our Knox Energy partnership in Tennessee. The well counts are exclusive of gob wells, which are expected to number 55. Additionally, CNX Gas plans to drill 21 frac wells that were carried over from the 2005 drilling program.

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Sales

CNX Gas enters into various physical gas sales transactions with both gas marketers and various other counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than pipeline outages related to maintenance, we have not failed to deliver quantities required under contract. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial, as well as physical, hedges, represented approximately 70% of our produced gas sales volumes for the twelve months ended December 31, 2005 at an average price of $4.77 per mcf. As of December 31, 2005, we expect these transactions will cover approximately 31% of our estimated 2006 production.

We also have an operational balancing agreement with Columbia Gas Transmission Corporation (“Columbia”). This agreement is in accordance with the Council of Petroleum Accountants Societies’ definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CNX Gas is responsible for monitoring this imbalance and making adjustments to sales volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser. The financial impacts of these imbalances were an $899 increase to expense and a $266 decrease to expense for the twelve months ended December 31, 2005 and 2004 respectively.

Due to the potential for curtailments on portions of the interruptible capacity allocated to us, CNX Gas purchased firm transportation capacity on the Columbia interstate pipeline. CNX Gas anticipates that there will be on-going curtailments of interruptible capacity as a result of the increased demand on the Columbia interstate pipeline, however this firm transportation capacity should offset a portion of the expected impacts from these curtailments. As of December 31, 2005, CNX Gas has secured firm transportation capacity to cover more than its 2006 hedged production. CNX Gas also participates in the short-term firm transportation markets to manage flows as market conditions dictate.

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 17 of the notes to the consolidated annual financial statements included in Item 8 of Part II of this Annual Report.

Gathering

Our gas operations in Central Appalachia built separate gathering systems to deliver most of our gas to third party marketers. While each gathering system begins at the individual wellhead, gas from wells is transported to market in each case by CSGC’s major gathering system. CSGC is a wholly owned subsidiary which operates two major gathering trunklines. The first line is a 50-mile, 16-inch line that is capable of gathering 100 mmcf of gas per day. This line has processing and compression facilities and connects with Columbia’s interstate pipeline in Mingo County, West Virginia. The second line is a 30-mile, 20-inch line capable of gathering 150 mmcf of gas per day. This gathering line also connects with Columbia’s interstate pipeline in Wyoming County, West Virginia. This gathering system has a combined capacity of 250 mmcf per day compared with our 2005 annual average daily gross production of 148 mmcf. This excess capacity is vital to our plans to continue to grow our production volumes in Central Appalachia.

Transportation

The final transport of gas to market is handled by third party, interstate gas pipeline operators such as Columbia. In 2004, for the first time since we began producing gas, we experienced curtailments of pipeline capacity on Columbia’s line that transports most of our Central Appalachia gas to market. We experienced similar curtailments on KA-20 in 2005 and expect additional curtailments in 2006, primarily during April-July of

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2006. The growth of production in the Appalachian basin, expansion of the Cove Point liquid natural gas terminal downstream on the pipeline and summer season maintenance have resulted in constraints on the Columbia pipeline system.

We also intend to gain access to the ETNG pipeline, which is south of our Central Appalachia operations. ETNG has received the approval of the Federal Energy Regulatory Commission (“FERC”) for the construction of a 32-mile lateral pipeline, called Jewell Ridge Lateral, that will transport gas from our Central Appalachia operations to ETNG’s major transportation pipeline to the south. The FERC approval is subject to certain conditions, which ETNG is working to satisfy. Jewell Ridge Lateral is expected to be in service in the summer of 2006 and will provide us with an alternate transportation route to the northeast markets we currently serve as well as access to east coast markets.

Reserves

CNX Gas’ reserves are either owned or leased. Proved reserves are the estimated quantities which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the SEC Rule 4.10(a) of Regulation S-X.

	Net Reserves (mmcfe)
	As of December 31,
	2005		2004		2003
	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates
Estimated proved developed reserves	549,574	2,672	395,152	1,489	352,935	843
Estimated proved undeveloped reserves	578,150	—	647,251	896	649,865	738
Total estimated proved developed and undeveloped reserves	1,127,724	2,672	1,042,403	2,385	1,002,800	1,581

Discounted Future Net Cash Flows

The following table shows our net estimated proved developed and proved undeveloped reserves, our estimated future net cash flows and total standardized measure of discounted future net cash flows at 10%:

	Discounted Future Net Cash Flows ($ in thousands)
	As of December 31,
	2005		2004		2003
Future net cash flows	$	5,149,938	$	2,872,571	$	2,708,797
Total PV-10 measure of pre tax discounted future net cash flows (1)	$	3,051,866	$	1,655,232	$	1,556,866
Total standardized measure of after tax discounted future net cash flows	$	1,870,794	$	1,029,538	$	1,011,186

(1) We calculate our PV-10 value in accordance with the following table. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes

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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.

Reconciliation of PV-10 to Standardized Measure:

	As of December 31,
	2005			2004			2003
Future cash inflows	$	11,675,551		$	6,337,257		$	5,792,348
Future Production Costs		(2,852,033	)		(1,453,364	)		(1,314,691	)
Future Development Costs (including abandonments)		(422,315	)		(265,540	)		(307,075	)
Future net cash flows		8,401,203			4,618,353			4,170,582
10% discount factor		(5,349,337	)		(2,963,121	)		(2,613,716	)
PV-10 (Non-GAAP measure)		3,051,866			1,655,232			1,556,866
Undiscounted Income Taxes		(3,251,265	)		(1,745,782	)		(1,461,785	)
10% discount factor		2,070,193			1,120,088			916,105
Discounted Income Taxes		(1,181,072	)		(625,694	)		(545,680	)
Standardized GAAP measure	$	1,870,794		$	1,029,538		$	1,011,186

Competition

Competition throughout the country is regionalized. We operate 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 cost and the proximity of gas fields to customers.

Subsidiaries and Joint Ventures

Prior to August 2005, we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy. Those companies included three subsidiaries (CNX Gas Company LLC; Greene Energy—since merged into CNX Gas Company LLC; and CSGC); and four joint ventures (Coalfield Pipeline; Knox Energy; Buchanan Generation and an arrangement with Kelly Oil and various other entities). As part of our separation from CONSOL Energy, we have executed with CONSOL Energy a master separation agreement that transferred to us CONSOL Energy’s interests in these various subsidiaries and joint venture interests.

The following describes the material joint ventures in which we directly or indirectly hold interests.

Knox Energy LLC

This limited liability company was formed in Tennessee in 2001 and is owned 50% by CNX Gas Company LLC and 50% by New River Energy, LLC (New River Energy). Knox Energy is engaged in certain drilling operations in Tennessee, covering approximately 208,000 gross conventional acres in Tennessee. A management agreement, dated September 7, 2001, between CNX Gas Company LLC and New River Energy, governs the operation of the project wells. Under the management agreement, CNX Gas Company LLC, as operator, is responsible for drilling, completing and operating gas, CBM and oil wells. As operator, CNX Gas Company LLC has full control of the operation of the wells and is responsible for obtaining all necessary permits, building roads, finding suitable drilling rigs, and taking all other action as is customarily required to operate the wells. The management agreement does not have a defined term.

Knox Energy is also engaged in a project with Atlas America, Inc. (Atlas). In September 2004, Knox Energy entered into a three year drilling and operating agreement with Atlas which relates to certain natural gas

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and oil wells located in Anderson, Campbell, Claiborne, Morgan, Roane and Scott Counties, Tennessee. Atlas is the operator of the wells; Knox Energy, as the non-operator, is required to pay its proportionate share of drilling and other costs to Atlas. Knox Energy has the right to participate in a 50% working interest in each of the wells drilled after the initial ten permitted wells, under the agreement. Upon such participation, Knox Energy has the right to receive an overriding royalty payment equal to 1.5625%. Under the agreement, Knox Energy is prohibited from transferring its rights to explore or produce the natural gas or oil, other than methane gas from coalbeds or coal mines, from certain property to any party other than Atlas until June 30, 2007. Substantially all gas produced from the wells is transferred through the Coalfield Pipeline, pursuant to an agreement between Atlas and Coalfield Pipeline.

Coalfield Pipeline Company

Coalfield Pipeline is a Tennessee corporation, formed in 2001. Coalfield Pipeline is owned 50% by CNX Gas and 50% by New River Energy. Coalfield Pipeline compresses and, through its pipeline, transports natural gas from wells.

Coalfield Pipeline has an agreement with Atlas whereby it will transport all natural gas from the wells that Atlas drills pursuant to the Atlas agreement with Knox Energy. Also, Coalfield Pipeline has entered into gas purchase contracts with various third parties, including Ariana Energy, to transport all of their gas from their facilities.

Buchanan Generation, LLC

This Virginia limited liability company is owned 50% by CNX Gas and 50% by Allegheny Energy, to develop and operate a peaker power generation facility that is located in Buchanan County, Virginia. In 2002, the parties completed construction of Buchanan Generation’s LM 6000 combustion turbine 88-megawatt electric generating peaking facility.

This facility operates on gas produced by CNX Gas’ Central Appalachia operations. The generation facility is used to meet peak load demands for electricity by processing the CBM gas that CNX Gas produces. Because it is a peaking power facility, it does not operate at all times of the year, but the facility does provide a potential sales outlet for our gas of approximately 22 mmcf per day. Buchanan Generation’s facilities include the power plant used to generate electricity, as well as a water treatment site and facility, the generation facilities, and a gas extension easement. Allegheny Energy is the operator of the facility. Additionally, Buchanan Generation and Allegheny Energy entered into a marketing agreement, whereby Allegheny Energy will market for sale, on an exclusive basis, all electricity produced from the generation facilities.

Employee and Labor Relations

As of December 31, 2005, CNX Gas had 134 employees. None of our employees is represented by a union. We believe our relationship with our employees is satisfactory.

Regulations

The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of wells after gas operations are completed, the discharge or release of materials into the environment, and the effects of gas well operations on groundwater quality and availability. 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.

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Environmental Regulation of Gas Operations

Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay 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.

It is not possible to quantify the costs of compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the twelve months ended 2005, 2004 and 2003. CNX Gas expects to incur $1.1 million related to water disposal wells in 2006. Any environmental costs are in addition to well closing costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially 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 cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for disposal.

CNX Gas is subject to various generally-applicable federal environmental laws, including the following:

• the Clean Air Act;

• the Clean Water Act;

• the Toxic Substances Control Act;

• the Endangered Species Act:

• the Resource Conservation and Recovery Act; and

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

as well as state laws of similar scope and substance in each state in which we operate.

These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations

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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 liability: to correct such violations; to provide additional environmental controls; to obtain required permits; and to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.

From time to time, we have been the subject of investigations, administrative proceedings, and litigation, by government agencies and third parties, relating to environmental matters. We may become involved in future proceedings, litigation or investigations and incur liabilities that could be materially adverse to us.

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. In the past, the federal government has regulated the prices at which gas could be sold. 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. Deregulation of wellhead sales in the natural gas industry began with the enactment of the Natural Gas Policy Act in 1978. 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.

Commencing in April 1992, the Federal Energy Regulatory Commission issued Order Nos. 636, 636-A, 636-B, 636-C and 636-D, which require interstate pipelines to provide transportation services separate, or “unbundled,” from the pipelines’ sales of gas. Also, Order No. 636 requires pipeline operators to provide open access transportation on a nondiscriminatory basis that is equal for all natural gas shippers. Although Order No. 636 does not directly regulate CNX Gas’ production activities, the Federal Energy Regulatory Commission has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.

The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the Federal Energy Regulatory Commission continues to review and modify its open access regulations. In particular, the Federal Energy Regulatory Commission has reviewed its transportation regulations, including how they operate in conjunction with state proposals for retail gas marketing restructuring, whether to eliminate cost-of-service rates for short-term transportation, 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. In February 2000, the Federal Energy Regulatory Commission issued Order No. 637 amending certain regulations governing interstate natural gas pipeline companies in response to the development of more competitive markets for natural gas and natural gas transportation. The goal of Order No. 637 is to “fine tune” the open access regulations implemented by Order No. 636 to accommodate subsequent changes in the market. Key provisions of Order No. 637 include:

(1) waiving the price ceiling for short-term capacity release transactions until September 30, 2002 (which was reversed pursuant to an order on remand issued by the Federal Energy Regulatory Commission on October 31, 2002);

(2) permitting value-oriented peak/off-peak rates to better allocate revenue responsibility between short-term and long-term markets;

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(3) permitting term-differentiated rates, in order to better allocate risks between shippers and the pipeline;

(4) revising the regulations related to scheduling procedures, capacity, segmentation, imbalance management, and penalties;

(5) retaining the right of first refusal and the five year matching cap for long-term shippers at maximum rates, but significantly narrowing the right of first refusal for customers that the Federal Energy Regulatory Commission does not deem to be captive; and

(6) adopting new web site reporting requirements that include daily transactional data on all firm and interruptible contracts and daily reporting of scheduled quantities at points or segments.

The new reporting requirements became effective on September 1, 2000. 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. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CNX Gas’ gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CNX Gas does not believe that it would be affected by such regulation any differently than other natural gas producers or gatherers. 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 it believes 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 are 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—United States

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 and the disposal of fluids used in connection with operations. 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 and 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,

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and generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and CNX Gas is unable to predict the future cost or impact of complying with such regulations.

Ownership of Mineral Rights

The majority of our drilling operations are conducted on properties related to CONSOL Energy’s coal holdings. The typical arrangement is for CONSOL Energy to obtain ownership or leasehold rights in the properties and then assign to us the CBM and other gas rights. Consequently, our existing rights are often dependent on CONSOL Energy having obtained valid title to its properties.

CONSOL Energy’s past practice has been to acquire ownership or leasehold rights to its coal properties prior to conducting its coal mining operations. Given CONSOL Energy’s long history as a coal producer we believe it has a well developed ownership position relating to its coal holdings. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to its coal holdings, its ownership position relating to these property estates is less developed. As is customary in the coal and gas industry, a summary review of the title to coal, CBM and other gas rights is made on properties at the time of the acquisition of the other rights in the properties. Prior to the commencement of gas drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence our drilling operations on a property until we have cured any material title defects on such property. We completed title work on substantially all of our producing properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the gas industry. Our natural gas properties are subject to customary royalty and other interests and other burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to conventional 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 proven reserves are in Virginia, which has been the focus of our developmental efforts to date. 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. This Court has also found that the owner of the CBM did not have the right to fracture the coal

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in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.

In addition, Virginia has established the Virginia Gas and Oil Board and a procedure for the development of CBM by an operator in those instances where the owner of the CBM has not leased it to the operator or in situations where there are conflicting claims of ownership of the CBM. The general practice is to force pool both the coal owner and the gas owner. In those instances, any royalties otherwise payable are paid into escrow and the burden then is upon the conflicting claimants to establish ownership by court action. The Virginia Gas and Oil Board does not make ownership decisions.

West Virginia

In West Virginia, its Supreme Court has held that, in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2005, 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. At the current locations where we produce CBM in West Virginia, we were able to acquire ownership of the CBM by acquiring additional rights to CBM from the owners of all of the possibly relevant real estate interest holders.

West Virginia has enacted a law, the Coalbed Methane Well and Units Act (the “West Virginia Act”), regulating the commercial recovery and marketing of CBM. Although the West Virginia Act does not specify who owns, or has the right to exploit, CBM in West Virginia and instead refers ownership disputes to judicial resolution, it contains provisions similar to Virginia’s forced pooling law. Under the pooling provisions of the West Virginia Act, an applicant who proposes to drill can prosecute an administrative proceeding with the West Virginia coalbed methane review board to obtain authority to produce CBM from pooled acreage. Owners and claimants of CBM interests who have not consented to the drilling are afforded certain elective forms of participation in the drilling (e.g., royalty or owner) but their consent is not required to obtain a pooling order authorizing the production of CBM by the operator within the boundaries of the drilling unit. The West Virginia Act also provides that, where title to subsurface minerals has been severed in such a way that title to coal and title to natural gas are vested in different persons, the operator of a CBM well permitted, drilled and completed under color of title to the CBM from either the coal seam owner or the natural gas owner has an affirmative defense to an action for willful trespass relating to the drilling and commercial production of CBM from that well.

We anticipate in future years to more actively explore and develop Northern Appalachian CBM in Pennsylvania and 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 in West Virginia 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 expect to develop 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 in the case of West Virginia to use force pooling under the West Virginia Act.

Other States

We have been transferred rights to extract CBM held by CONSOL Energy in other states where it has coal reserves, including the states which comprise the Illinois Basin and certain other Western Basins. We have not examined the rights we have received in those states or applicable state law. The ownership of CBM in these other states may also be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.

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GLOSSARY OF NATURAL GAS AND COAL TERMS

The following is a description of the meanings of some of the oil and gas industry terms used in this Annual Report.

Appalachian Basin. A mountainous region in the eastern United States, running from northern Alabama to New York, and including parts of Georgia, South Carolina, North Carolina, Tennessee, Kentucky, Pennsylvania, Virginia, and all of West Virginia.

Bcf. Billion cubic feet of natural gas.

Bcfe. Billion cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Btu or British Thermal Unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

CBM. Coalbed methane.

Central Appalachia. As used in this Annual Report, Central Appalachia includes Virginia and southern West Virginia.

Coal Seam. A single layer or stratum of coal.

Completion. The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved boundaries of an oil or natural gas reservoir with the intention of completing the stratigraphic horizon known to be productive.

Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Exploitation. Ordinarily considered to be a form of development within a known reservoir.

Exploratory well. A well drilled to find and produce oil or gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

Farm-in or farm-out. An agreement under which the owner of a working interest in an oil or gas lease assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Frac well. A vertical well drilled in advance of mining and producing from zones artificially fractured or stimulated and which is capable of producing natural gas.

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Gathering system. Pipelines and other equipment used to move natural gas from the wellhead to the trunk or the main transmission lines of a pipeline system.

Gob. The de-stressed zone associated with any full seam extraction of coal that extends above and below the mined out coal seam, and which may be sealed or unsealed.

Gob gas. Gas produced from (a) a well drilled in advance of mining or after mining for the purpose of extracting natural gas from the gob or (b) a frac well that is recompleted for the purpose of extracting natural gas from the gob.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

Longwall mining. An automated form of underground coal mining characterized by high recovery and extraction rates. A high-powered cutting machine is passed across the exposed face of coal, shearing away broken coal, which is continuously hauled away by a floor-level conveyor system. Longwall mining extracts all machine-minable coal between the floor and ceiling within a contiguous block of coal, known as a panel, leaving no support pillars within the panel area. Longwall mining is done under movable roof supports that are advanced as the bed is cut. The roof in the mined-out area is allowed to fall as the mining advances.

mcf. Thousand cubic feet of natural gas.

mcfe. Thousand cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

MMBtu. Million British thermal units.

mmcf. Million cubic feet of natural gas.

mmcfe. Million cubic feet equivalent, determined using the ratio of six mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Northern Appalachia. As used in this Annual Report, Northern Appalachia includes southwestern Pennsylvania and northern West Virginia.

NYMEX. The New York Mercantile Exchange.

Panel. A contiguous block of coal that generally comprises one operating unit.

Pay zone. The section of rock, from which gas is expected to be produced in commercial quantities.

PV-10 or present value of estimated future net revenues. An estimate of the present value of the estimated future net revenues from proved gas reserves at a date indicated after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC’s practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

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Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves. Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

Proved reserves. The estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.

Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

Reserve life index. This index is calculated by dividing total proved reserves by the production from the previous year to estimate the number of years of remaining production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Shut in. Stopping an oil or gas well from producing.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether or not such acreage contains proved reserves.

Vertical-to-horizontal well. A well in which the drilling from the surface initially proceeds vertically until reaching a particular depth, at which point, the drill bit is turned to proceed at up to 90 degrees from vertical in order to follow a particular stratum or pay zone.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production.

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 “Officers of the Registrant” (included herein pursuant to Item 401(b) of Regulation S-K).

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ITEM 1A. RISK FACTORS

In addition to the trends and uncertainties described in Item I of this Annual Report and in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” CNX Gas is subject to the trends and uncertainties set forth below.

Natural gas and oil prices are volatile, and a decline in natural gas and oil 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 and oil. 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 and oil 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. However, in 2006 we expect to be significantly less hedged than we have been in the past. Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the domestic and foreign supply of natural gas and oil;

• the price of foreign imports;

• overall domestic and global economic conditions;

• the consumption pattern of industrial consumers, electricity generators and residential users;

• weather conditions;

• technological advances affecting energy consumption;

• domestic and foreign governmental regulations;

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

• the price and availability of alternative fuels.

Many of these factors may be beyond our control. Because approximately 100% of our estimated proved reserves as of December 31, 2005 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Earlier in this decade, natural gas prices were much lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis, but also 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 oil and natural gas properties for impairments. 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 carry 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 proven recoverable gas reserves, and inaccuracies in our estimates could result in lower than expected reserve quantities and a lower present value of our reserves.

Natural gas reserve engineering requires subjective estimates of underground accumulations of natural gas and assumptions concerning future natural gas prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be incorrect. We have in the past retained the services of independent petroleum

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engineers to prepare reports of our proved reserves. Over time, material changes to reserve estimates may be made, taking into account the results of actual drilling, testing, and production. Also, we make certain assumptions regarding future natural gas prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual figures could greatly affect our estimates of our reserves, the economically recoverable quantities of natural gas attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of gas we ultimately recover being different from reserve estimates.

The present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of our estimated natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves on prices and costs. However, actual future net cash flows from our gas and oil properties also will be affected by factors such as:

• geological conditions;

• changes in governmental regulations and taxation;

• assumptions governing future prices;

• the amount and timing of actual production;

• future operating costs; and

• capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2005 would decrease from $3,051.9 million to $3,015.2 million.

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, 2005, 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;

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• pressure or irregularities in geologic formations;

• equipment failures or repairs;

• fires or other accidents;

• adverse weather conditions;

• reductions in natural gas and oil 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 business depends on transportation facilities owned by others. Disruption of, capacity constraints in, or proximity to pipeline systems could limit our sales and increase costs of producing 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, and our transportation costs could increase, 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. In the current year, we have had to shut-in production due to shipping capacity limitations on Columbia’s KA-20 line that transports most of our Virginia gas to market and to compete with other producers for a portion of the pipeline capacity by purchasing firm transportation capacity that added to our cost. Although we have reached an agreement with ETNG, to gain access to its pipeline, we may not be able to successfully gain access to that pipeline. If our sales are reduced because of transportation constraints, our revenues will be reduced, which will also increase our costs. If we are not successful with our bid for transportation capacity and we do not have the ability to store gas, we may have to reduce production.

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, its operating results and financial position may be adversely affected. For example, one of our competitive strengths is as a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive strength in that area.

In addition, larger companies may be able to pay more to acquire new properties for future exploration, limiting our ability to replace gas we produce or to grow our production. Our ability to acquire additional properties and to discover new resources also depends on our ability to evaluate and select suitable properties and to consummate these transactions in a highly competitive environment.

The coal beds from which we produce methane gas frequently contain water that may hamper our ability to produce gas in commercial quantities.

Coal beds frequently contain water that must be removed in order for the gas to detach from the coal and flow to the well bore. Our ability to remove and dispose of sufficient quantities of water from the coal seam will determine whether or not we can produce gas in commercial quantities. The cost of water disposal may affect our profitability.

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

Our business requires disciplined execution at all levels of our organization to ensure that we continually develop our reserves and produce gas at profitable levels. This execution requires an experienced and talented management and production team. If we were to lose the benefit of the experience, efforts and abilities of any of our key executives and/or the members of our team that have developed substantial expertise in coalbed methane extraction, such as Nicholas DeIuliis, our Chief Executive Officer and President and Ronald Smith, our Executive Vice President and Chief Operating Officer, our business could be materially adversely affected. No employment agreements have been or are expected to be executed with these key executives. Furthermore, our ability to manage our growth, if any, will require us to continue to train, motivate and manage our employees and to attract, motivate and retain additional qualified managerial and production personnel. Competition for these types of personnel is intense, and we may not be successful in attracting, assimilating and retaining the personnel required to grow and operate our business profitably.

We are party to, and may in the future become party to, joint ventures and other arrangements with third parties that may impact our operations and our financial performance.

We have entered into several joint venture arrangements with third parties. For example, we are involved with third parties in Knox Energy (exploration and production), Coalfield Pipeline Company (Coalfield Pipeline) (gas pipeline) and Buchanan Generation, LLC (Buchanan Generation) (peaker electrical power generation plant) and in a participation agreement with Kelly Oil & Gas, Inc. (Kelly Oil), Excelsior Exploration Corporation, KWR Ventures, LLC and Ceja Corporation (exploration and production). We may also enter into other arrangements like these in the future. For example, we have an agreement with ETNG, whereby ETNG would construct and transport gas on a pipeline running from its main trunk line up to our Virginia operations. In many instances we depend on these third parties for elements of these arrangements that are important to the success of the joint venture and the performance of these third parties’ obligations or their ability to meet their obligations under these arrangements are outside our control. If these parties do not meet or satisfy their obligations under these arrangements, the performance and success of these arrangements may be adversely affected. If our current or future joint venture partners are unable to meet their obligations we may be forced to undertake the obligations ourselves and/or incur additional expenses in order to have some other party perform such obligations. In such cases we may also be required to enforce our rights that may cause disputes among our joint venture parties and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint ventures and/or our ability to enter into future joint ventures.

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 and 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.

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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.

We may incur additional costs to produce gas because our chain of title work for gas rights in some of our properties may be inadequate or incomplete.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. These properties were acquired by our principal stockholder 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 review gas estate title work when we consider exploratory or production drilling and to obtain any additional rights needed to perfect our ownership for production purposes of the gas estate. In addition, the steps needed to perfect our ownership varies from state to state and some states permit us to produce the gas without perfected ownership under forced pooling arrangements while other states do not permit this. As a result, we may have to incur title costs and pay royalties to produce gas on acreage that we control and these costs may be material and vary depending upon the state in which we operate. In addition, although CONSOL Energy has conveyed to us all of their right to extract and produce CBM from locations where they possess rights to coal, in some cases CONSOL Energy may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop the CBM with CONSOL Energy’s mining of coal, as provided in the master cooperation and safety agreement. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce CBM from those locations or the feasibility of obtaining those rights.

In addition to acquiring these property right assets on an “as is where is basis”, we have assumed all of the liabilities related to these assets, even if those liabilities were as a result of activities occurring prior to CONSOL Energy’s transfer of those assets to us. Our assumption of these liabilities is subject to the following allocation: we will be responsible for the first $10 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 need to use unproven technologies to extract coalbed methane on some of our properties.

Our ability to extract gas in coal seams with lower gas content per ton of coal such as the Pittsburgh #8 seam requires the use of advanced technologies that are still being developed and tested. Horizontal drilling is the

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advanced technology currently being used. This technique, applied in coal, requires a well design that promotes simultaneous production of water and methane without significant back-pressure, a well that can be subsequently mined through without jeopardizing mine-safety and a well that will ensure well bore integrity throughout its projected life.

Other persons could have ownership rights in our advanced extraction techniques which could force us to cease using those techniques or pay royalties.

Although we believe that we hold sufficient rights to all of our advanced extraction techniques, other persons could contest our rights and claim ownership of one or more of our advanced techniques for extracting CBM. For example, a third party recently asserted that several of our drilling techniques infringed several patents held by that person. A successful challenge to one or more of our advanced extraction techniques could adversely impact our financial performance and results of operation. We might have to pay a royalty which would increase our production costs or cease using that technique which could raise our production costs or decrease our production of CBM. In addition, we could incur substantial costs in defending patent infringement claims, obtaining patent licenses, engaging in interference and opposition proceedings or other challenges to our patent rights or intellectual property rights made by third parties or in bringing such proceedings.

Currently the vast majority of our producing properties are located in two 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 two counties in Virginia. As a result of this concentration, we may be disproportionately exposed to the impact of delays or interruptions of production from these wells caused by significant governmental regulation, transportation capacity constraints, curtailment of production, natural disasters or interruption of transportation of natural gas produced from the wells in this basin or other events which impact this area.

We do not insure against all potential operating risks. We may incur substantial losses and be subject to substantial liability claims as a result of our natural gas operations.

We maintain insurance for some, but not all, of the potential risks and liabilities associated with our business. For some risks, we may not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented. As a result of market conditions, premiums and deductibles for certain insurance policies can increase substantially, and in some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. As a result, we may not be able to renew our existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all. Although we maintain insurance at levels we believe are appropriate and consistent with industry practice, we are not fully insured against all risks, including drilling and completion risks that are generally not recoverable from third parties or insurance. In addition, pollution and environmental risks generally are not fully insurable. As part of our separation from CONSOL Energy, we assumed all of the liabilities related to the gas assets and operations which were transferred to us, including liabilities resulting from operations prior to the effective date of the separation. Arrangements with CONSOL Energy significantly limit our seeking indemnification from CONSOL Energy for unknown liabilities that we have assumed. Losses and liabilities from uninsured and underinsured events and delay in the payment of insurance proceeds could have a material adverse effect on our financial condition and results of operations.

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Risks Relating to Our Relationship with CONSOL Energy

Our principal stockholder, CONSOL Energy, is in a position to affect our ongoing operations, corporate transactions and other matters, and some of our directors also serve on its board of directors and/or are employees of CONSOL Energy, creating potential conflicts of interest.

Our principal stockholder, CONSOL Energy, owns 81.5% of our outstanding shares of common stock. As a result, CONSOL Energy will be able to determine the outcome of all corporate actions requiring stockholder approval. For example, CONSOL Energy will continue to control decisions with respect to:

• the election and removal of directors;

• mergers or other business combinations involving us;

• future issuances of our common stock or other securities; and

• amendments to our certificate of incorporation and bylaws.

Any exercise by CONSOL Energy of its control rights may be in its own best interest which may not be in the best interest of our other stockholders and our company. CONSOL Energy’s ability to control our company may also make investing in our stock less attractive. These factors in turn may have an adverse effect on the price of our common stock.

In addition, some of our directors serve as directors or officers of CONSOL Energy, and/or own CONSOL Energy stock, stock units or options to purchase CONSOL Energy stock, or they may be entitled to participate in the CONSOL Energy compensation plans. CONSOL Energy provides, and may in the future provide additional, cash- and equity-based compensation to employees or others based on CONSOL Energy’s performance. These arrangements and ownership interests or cash- or equity-based awards could create, or appear to create, potential conflicts of interest when directors or executive officers who own CONSOL Energy stock or stock options or who participate in the CONSOL Energy equity plan arrangements are faced with decisions that could have different implications for CONSOL Energy than they do for us. These potential conflicts of interest may not be resolved in our favor.

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 its substantial influence and control over us in favor of its own interests over our interests. Our certificate of incorporation and the master cooperation and safety agreement entitle CONSOL Energy to various corporate opportunities which might otherwise have belonged to us and relieve CONSOL Energy and its directors, officers and employees from owing us fiduciary duties with respect to such opportunities.

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

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to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future which also may not be deemed to be independently negotiated.

Our 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.

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 recently 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 Inc. has advised us that as of the date of this Annual Report, CONSOL Energy has no plan or intention regarding its shares of our common stock and if CONSOL Energy were to make a distribution or otherwise dispose of its remaining ownership interest in us, our common stock price could be adversely affected.

Unless and until CONSOL Energy distributes to its stockholders, either in a tax-free spin-off or one or more special dividends, or sells the controlling amount of our common stock it owns, we will face the risks discussed in this Annual Report relating to CONSOL Energy’s control of us and potential conflicts of interest between CONSOL Energy and us. CONSOL Energy may elect not to make such a distribution or sale or it could at any time make that distribution or sale. Additionally, the market price of our common stock could decline as a result of market sales by CONSOL Energy, a distribution of our common stock to CONSOL Energy’s stockholders or the perception that such sales or distributions will occur. These sales or distributions also might make it difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate. Future sales of our common stock could impact the price at which the shares purchased or acquired by our investors may be sold in the future.

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

In many places where we extract CBM, the coal estate is dominant. Where our principal stockholder conducts mining activity, CONSOL Energy could exercise its rights to determine when and where certain drilling

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can take place in order to ensure the safety of the mine or to protect the mineability of the coal. For example, if CONSOL Energy is required to cease mining activities due to an event causing a coal mine to be idled, that cessation of coal mining could prohibit us from producing gas from that or related sites until the coal mining activities commence again, which could adversely affect our financial condition or operations. We have 271 Bcf of proved undeveloped reserves that are dependent on the mining of coal by CONSOL Energy.

We may lose certain synergistic advantages by separating ourselves from our current owner.

Because approximately 17% of our gas production is associated with mining activities by our principal stockholder, coordination between mining and gas operations can optimize overall energy production. We have 271 Bcf of proved undeveloped reserves that are dependent on the mining of coal by CONSOL Energy. If CONSOL Energy were to dispose of a significant interest in us, coordination between us and CONSOL Energy’s mining subsidiaries may be more difficult to accomplish.

ITEM 2. PROPERTIES

Our corporate headquarters are located at 4000 Brownsville Road, South Park, PA 15129-9545. Our other properties are described under “Gas Operations—Areas of Operation” in ITEM 1.

ITEM 3. LEGAL PROCEEDINGS

CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2001. For these years, CNX Gas has filed appropriate returns and has paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County as of December 31, 2005. Additionally, on April 29, 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a “Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code §8.01-184” against us in the Circuit Court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002. The complaint alleges that we failed to properly calculate the amount of license taxes we owed to Buchanan County related to our production and sale of CBM gas in Buchanan County. Buchanan County is seeking a determination by the court that we have calculated, and continue to calculate, the license tax in an improper manner. We have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability on our balance sheet in an amount based on the difference between our calculation of the tax and Buchanan County’s calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

CDX Gas, LLC has alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX has demanded that we enter into a business arrangement with CDX to use its patented technology. Alternatively, CDX has informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly covered by their patents. While CDX has not formally identified the wells where we used the allegedly infringing technology, we believe that 23 of our producing wells to date could be covered by their claim. CDX has also suggested that we breached a confidentiality agreement that one of our affiliates entered into with them in 2001. We deny all of these allegations and intend to vigorously contest them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania, seeking a judicial determination to the effect that the CDX patents are invalid and unenforceable and that we do not infringe any valid and enforceable claim of the CDX patents. CDX has filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain of their patents. This litigation is in a very early stage and we cannot predict the outcome.

In 1999, CNX Gas was named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty

34

owners and to a class of plaintiffs who have yet to be determined. The claim of underpayment of royalties related to the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post production expenses of gathering compression and transportation. CNX Gas was ordered to, and subsequently in 2002 paid, approximately $7,000 to the group of royalty owners that brought the suit. An estimate of the payment was appropriately accrued in other cost of goods sold in previous periods. A final payment was made to the plaintiffs in 2003 for approximately $6,000 to adjust all royalties owed to the plaintiffs from the date of the court ruling forward, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of the aforementioned suit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various royalty owners using the court determined deductions from the settled case. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

In addition to the foregoing, CNX Gas is subject to various pending and threatened lawsuits and claims arising in the ordinary course of its business. While the relief claimed in these matters may be significant, we are unable to predict with certainty the ultimate outcome of such lawsuits and claims. We have established reserves for pending litigation which we believe are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against CNX Gas will not materially affect the financial position of CNX Gas.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

None.

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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”. Our common stock began trading on January 19, 2006, following the effectiveness of our resale registration statement on Form S-1.

On January 19, 2006, the high and low sales prices of our common stock on the NYSE were $22.65 and $21.78, respectively. On February 15, 2006, the high and low sales prices of our common stock on the NYSE were $22.40 and $21.40, respectively.

As of February 10, 2006 there were three holders of record of the Company’s common stock; we believe that there are significantly more beneficial holders of our stock.

We currently intend to retain our earnings for the development of our business and do not expect to pay any cash dividends. Other than the special dividend of approximately $420.2 million we paid to CONSOL Energy with the net proceeds from the private placement of the shares of CNX Gas described below, we have not paid any cash dividends from the date of our inception.

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

Recent Sales of Unregistered Securities

During the past three years, we have issued and sold unregistered securities in the transactions described below:

(1) In July, 2005 we issued 100 shares of common stock to Consolidation Coal Company in exchange for $100 in connection with the incorporation of CNX Gas. We relied on the exemption under Section 4(2) of the Securities Act of 1933, as amended (the “Securities Act”), in connection with the offer and sale of those shares.

(2) On August 1, 2005, we issued 122,896,567 shares of common stock to our then sole stockholder, Consolidation Coal Company, in exchange for the contribution to us of all of CONSOL Energy Inc.’s (Consolidation Coal Company’s sole stockholder) gas business. We relied on the exemption under Section 4(2) of the Securities Act in connection with the offer and sale of those shares.

(3) On August 8, 2005 we completed a private placement of 24,292,754 shares of common stock, 21,778,867 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 1,086,980 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 1,426,907 of which were offered and sold to accredited investors pursuant Rule 506 under the Securities Act. Friedman, Billings, Ramsey & Co., Inc. (“FBR”) served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $23,321,044, was $365,363,020. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.

(4) On August 11, 2005, following the exercise by FBR of an over-allotment option in connection with the above referenced private placement, we completed the sale of 3,643,913 shares of common stock,

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822,702 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 51,300 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 2,769,911 of which were offered and sold to accredited investors pursuant Rule 506 under the Securities Act. FBR served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $3,498,157, was $54,804,452. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.

(5) In reliance on Rule 701 and Rule 506 of the Securities Act of 1933, during August 2005, CNX Gas issued options to purchase CNX Gas common stock to our employees and executive officers at an exercise price of $16.00 per share and restricted stock units to our non-employee and non-CONSOL Energy employee directors. We also granted a small number of options to new employees in September 2005 at an exercise price of $20.50 per share, and in November 2005, at an exercise price of $20.75 per share. A total of 358,370 options to purchase CNX Gas common stock were granted to CNX Gas employees, other than our executive officers. Messrs. DeIuliis, Smith, Johnson and Bench received stock options in the aggregate amount of 670,556 shares and Mr. Johnson received 2,969 restricted stock units. Similarly, we granted restricted stock units to each director of CNX Gas that is not an employee of CNX Gas or CONSOL Energy. Mr. Baxter, chairman of the board of directors, was granted 60,000 restricted stock units. Each other such director received 10,000 restricted stock units. The foregoing one-time grants were made in consideration for future service of the employees, executive officers and directors to CNX Gas.

The registration statement on Form S-1 (SEC File No. 333-127483), as amended, filed by the Company was declared effective by the Securities and Exchange Commission on January 18, 2006. CNX Gas registered for sale 27,936,667 shares of common stock, all of which were held by selling stockholders named in the registration statement. Under the registration statement, the shares can be offered and sold by the selling stockholders in one or more transactions at fixed prices, prevailing market prices or negotiated prices. CNX Gas did not sell any shares for our own account and did not receive any proceeds from the sale of securities by any selling stockholders. CNX Gas incurred expenses as detailed in the registration statement of approximately $1.17 million.

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ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the twelve months ended December 31, 2005, December 31, 2004 and December 31, 2003, are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2005 and 2004 and the related consolidated statements of income and cash flows for each of the twelve months ended December 31, 2005, 2004, and 2003, and the notes thereto appearing herein. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2002 and the twelve months ended December 31, 2001 are derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included in this Annual Report.

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

STATEMENTS OF INCOME DATA (In thousands)	Twelve Months Ended December 31,
	2005		2004		2003		2002		2001
RESULTS OF OPERATIONS
Sales—Outside	$	322,382	$	256,579	$	178,326	$	139,343	$	119,047
Sales—Related Party		6,052		22,036		32,572		9,542		5,288
Sales—Purchased Gas		275,148		112,005		—		—		—
Other income		9,859		6,916		4,485		2,068		403
TOTAL REVENUE AND OTHER INCOME		613,441		397,536		215,383		150,953		124,738
Lifting costs		26,794		23,939		20,761		16,297		13,513
Gathering and compression costs		40,623		37,021		28,914		24,749		18,759
Royalty		36,641		32,914		24,200		12,214		10,659
Purchased gas costs		278,720		113,063		—		—		—
Other		21,147		16,274		21,771		16,169		17,863
Equity in (earnings) loss of affiliates		149		2,423		2,932		3,312		(16,788	)
Selling, general and administrative		7,596		6,327		3,194		1,140		2,446
Depreciation, depletion and amortization		35,039		32,889		33,600		34,368		21,175
Interest Expense		14		—		—		—		—
TOTAL COSTS AND EXPENSES		446,723		264,850		135,372		108,249		67,627
Earnings before income taxes and cumulative effect of change in accounting principle		166,718		132,686		80,011		42,704		57,111
Income taxes		64,550		51,898		31,202		16,677		22,330
Earnings before cumulative effect of change in accounting principle		102,168		80,788		48,809		26,027		34,781
Cumulative effect of change in accounting for gas well closing costs (net of tax impact of $1,879)		—		—		2,905		—		—
NET INCOME	$	102,168	$	80,788	$	51,714	$	26,027	$	34,781
Earnings per share from continuing operations
Basic	$	0.76	$	0.66	$	0.40	$	0.21	$	0.28
Dilutive	$	0.76	$	0.66	$	0.40	$	0.21	$	0.28
Earnings per share from net income
Basic	$	0.76	$	0.66	$	0.42	$	0.21	$	0.28
Dilutive	$	0.76	$	0.66	$	0.42	$	0.21	$	0.28
Weighted average number of common shares outstanding
Basic		134,071,334		122,896,667		122,896,667		122,896,667		122,896,667
Dilutive		134,137,219		122,988,359		122,988,359		122,988,359		122,988,359

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BALANCE SHEETS DATA (In thousands)	At December 31,
	2005			2004			2003			2002			2001
Working capital (deficiency)	$	3,720		$	(35,030	)	$	(7,971	)	$	2,868		$	6,984
Total assets		874,856			723,290			664,635			598,236			527,109
Short-term debt		—			—			—			—			—
Long-term debt (including current portion)		—			—			—			—			—
Total deferred credits and other liabilities		109,226			205,614			170,520			114,902			86,701
Stockholders’ equity		679,472			462,556			464,232			468,617			431,582
CASH FLOW STATEMENTS DATA (5) (In thousands)	Twelve Months Ended December 31,
	2005			2004			2003			2002			2001
Net cash provided by operating activities	$	144,997		$	175,350		$	143,133		$	88,643		$	63,781
Net cash (used in) investing activities		(108,287	)		(93,114	)		(90,605	)		(101,472	)		(203,168	)
Net cash (used in) provided by financing activities		(16,640	)		(82,237	)		(52,526	)		12,831			139,387
OTHER OPERATING DATA	Twelve Months Ended December 31,
	2005			2004			2003			2002			2001
Net sales volumes (Bcf) (1)		48.39			48.56			44.46			41.30			33.92
Average sales price including effects of financial settlements ($ per mcf) (1)(2)	$	6.08		$	5.09		$	4.14		$	3.17		$	4.07
Total average costs ($ per mcf) (1)	$	2. 72		$	2.45		$	2.43		$	2.25		$	2.17
Net estimated proved reserves (Bcfe) (1)(3)		1,130			1,045			1,004			961			1,023
OTHER FINANCIAL DATA (In thousands)	Twelve Months Ended December 31,
	2005			2004			2003			2002			2001
Capital expenditures	$	110,752		$	89,753		$	83,869		$	61,705		$	211,715
EBIT (4)		166,314			132,686			80,011			42,704			57,111
EBITDA (4)		201,353			165,575			113,611			77,072			78,286

(1) For entities that are not wholly owned but in which CNX Gas owns at least a 50% equity interest, includes a percentage of their net production, sales or reserves equal to CNX Gas’ percentage equity ownership. Knox Energy makes up the equity earnings data in 2005, 2004, 2003 and part of 2002. Greene Energy was part of the equity earnings in 2002 and 2001. Pocahontas Gas Partnership accounts for the majority of the information reported as an equity affiliate for approximately eight months in the December 31, 2001 period. Sales of gas produced by equity affiliates were 0.23 Bcf for the twelve months ended December 31, 2005, 0.20 Bcf for the twelve months ended December 31, 2004, 0.08 Bcf for the twelve months ended December 31, 2003, 0.22 Bcf for the twelve months ended December 31, 2002 and 5.5 Bcf for the twelve months ended December 31, 2001.

(2) Represents average net sales price after the effect of derivative transactions.

(3) Represents proved developed and proved undeveloped gas reserves at period end.

(4) 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

39

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:

	Twelve Months Ended December 31,
(In thousands)	2005		2004		2003			2002		2001
Net income	$	102,168	$	80,788	$	51,714		$	26,027	$	34,781
Add: Interest expense		14		—		—			—		—
Less: Interest income		418		—		—			—		—
Less: Cumulative effect of changes in accounting for gas well plugging costs, net of income taxes of $1,879		—		—		(2,905	)		—		—
Add: Income tax expense		64,550		51,898		31,202			16,677		22,330
Earnings before net interest and taxes (EBIT)		166,314		132,686		80,011			42,704		57,111
Add: Depreciation, depletion and amortization		35,039		32,889		33,600			34,368		21,175
Earnings before net interest, taxes and depreciation, depletion and amortization (EBITDA)	$	201,353	$	165,575	$	113,611		$	77,072	$	78,286

(5) Amounts shown for the twelve months ended December 31, 2005 reflect the reclassification of certain amounts from the comparable line items on the unaudited consolidated statements of cash flows included in our press release dated January 25, 2006.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with “Selected Consolidated Financial and Other Data” and our consolidated financial statements and related notes appearing elsewhere in this Annual Report. This Annual Report on Form 10-K contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. See “PART I—Forward Looking Statements” and PART I-Item 1.A “Risk Factors”.

Overview

We are a natural gas exploration, development and production company with operations in the Appalachian Basin. We have operations in several states in the Appalachian Basin. We primarily are a CBM gas producer with industry-leading expertise in this type of gas extraction.

Effective as of August 8, 2005, we separated our gas business from CONSOL Energy. We undertook this separation to achieve the following objectives:

• achieve a higher valuation for our business than we believe could be achieved if we remained part of CONSOL Energy;

• allow us to use our own capital and borrowing capability, rather than compete for capital with the mining business, to more rapidly expand gas production from our proven reserves and unproven acreage; and

• allow our key managers to focus solely on the growth and operation of CNX Gas.

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 and natural gas and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with their coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will, among other things, provide us certain corporate staff services and coordinate our tax filings.

In August 2005, CNX Gas sold 27.9 million shares in a private placement transaction. The aggregate net proceeds of the transaction (approximately $420.2 million) were used to pay a special dividend to CONSOL Energy. CONSOL Energy continues to beneficially own 81.5% of our outstanding common stock.

We do not currently have any plans to pay dividends; rather, we intend to invest available cash into the development of our business, provided that we can do so at rates of return that exceed our cost of capital.

Our goal is to create shareholder value by efficiently increasing production and adding reserves, with a continued emphasis on safety. We believe that by working safely, we can enhance our productivity and continue to be a cost leader in the industry. During 2005, we achieved the following:

• generated net income in excess of $100 million;

• increased our proved reserve base by replacing 271 percent of our 2005 production;

• worked another year without a lost time accident; and

• nearly matched our 2004 production, despite losing over 4 Bcf of production due to affiliated mine situations and unaffiliated maintenance related capacity constraints on CNX Gas transportation capacity on the Columbia interstate pipeline.

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Our financial statements are consolidated within CONSOL Energy’s financial statements. For periods prior to August 8, 2005, when we were a wholly-owned subsidiary of CONSOL Energy, we developed separate financial statements for CNX Gas that allow us to report results as an independent company even though our results also are consolidated into CONSOL Energy’s financial statements.

Results of Operations

Twelve Months Ended December 31, 2005 compared with Twelve Months Ended December 31, 2004

(Amounts reported in thousands)

Net Income

Net income changed primarily due to the following items:

	2005		2004		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	322,382	$	256,579	$	65,803		25.6	%
Related Party Sales		6,052		22,036		(15,984	)	(72.5	)%
Purchased Gas Sales		275,148		112,005		163,143		145.7	%
Other Income		9,859		6,916		2,943		42.6	%
Total Revenue and Other Income		613,441		397,536		215,905		54.3	%
Costs and Expenses:
Lifting Costs		26,794		23,939		2,855		11.9	%
Gathering and Compression Costs		40,623		37,021		3,602		9.7	%
Royalty		36,641		32,914		3,727		11.3	%
Purchased Gas Costs		278,720		113,063		165,657		146.5	%
Other		21,147		16,274		4,873		29.9	%
Equity in (Earnings) Loss of Affiliates		149		2,423		(2,274	)	(93.9	)%
Selling, General and Administrative		7,596		6,327		1,269		20.1	%
Depreciation, Depletion and Amortization		35,039		32,889		2,150		6.5	%
Interest Expense		14		—		14		100.0	%
Total Costs and Expenses		446,723		264,850		181,873		68.7	%
Earnings Before Income Taxes		166,718		132,686		34,032		25.6	%
Income Taxes		64,550		51,898		12,652		24.4	%
Net Income	$	102,168	$	80,788	$	21,380		26.5	%

Net income for 2005 was improved primarily due to increased average sales prices. The increased revenues were offset, in part, by higher costs attributable to production taxes, royalties, firm transportation charges and general administrative charges.

Revenue and Other Income

Revenue and other income increased due to the following items:

	2005		2004		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	322,382	$	256,579	$	65,803		25.6	%
Related Party Sales		6,052		22,036		(15,984	)	(72.5	)%
Purchased Gas Sales		275,148		112,005		163,143		145.7	%
Other Income		9,859		6,916		2,943		42.6	%
Total Revenue and Other Income	$	613,441	$	397,536	$	215,905		54.3	%

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The increase in gas sales revenue was primarily due to a higher average sales price per thousand cubic feet in 2005 compared to 2004. Related party sales decreased due to the impacts of the Buchanan mine incidents. Purchased gas sales revenue increased due to the additional matching buy/sell arrangements required to sell our gas.

	2005		2004		Variance			Percentage Change
Produced Gross Sales Volumes (Bcf)		54.7		55.3		(0.6	)	(1.1	)%
Average Gross Sales Price (per mcf)	$	6.00	$	5.04	$	0.96		19.0	%

We believe the 2005 gas market price increases were largely driven by continued concerns over levels of North American gas production, as well as increased oil prices and favorable economic conditions in the United States that encourage demand for natural gas. The adverse effect of the 2005 hurricane season also shut-in significant portions of Gulf Coast gas, increasing the tight supply of gas, and leading to even higher prices in 2005. CNX Gas enters into various physical gas supply transactions with both gas marketers and other counterparties for terms varying in length. 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. These physical and financial hedges represented approximately 70% of our produced gas sales volumes for the twelve months ended December 31, 2005 at an average price of $4.77 per mcf. Despite the loss of approximately 4.0 Bcf related to the CONSOL Energy Buchanan Mine incidents and 1.4 Bcf related to maintenance related capacity constraints on CNX Gas transportation capacity on the Columbia interstate pipeline, sales volumes are only slightly lower in the 2005 period compared to the 2004 period. CNX Gas was able to offset these production losses with additional volumes coming online from our on-going drilling program, and by successfully initiating a frac well enhancement and stimulation program on wells unaffected by the mine incidents throughout the current year.

As a result of increased demand for pipeline use on the Columbia interstate pipeline and the potential for curtailment on portions of the shipment capacity allocated to CNX Gas, we purchased firm transportation capacity on the pipeline during 2005. This arrangement offset a portion of the expected impact from periodic curtailments. In April 2005, CNX Gas was given notice by Columbia regarding reductions in allowable gas flows due to routine maintenance and construction activities. Interruptible gas was completely shut in and our contracted firm transportation flows were reduced by 60%, which resulted in reduced revenues of approximately $6.8 million along with other smaller curtailments throughout the year that were also eventually lifted. Although CNX Gas anticipates that these pipeline constraints will be an on-going issue for the foreseeable future, we also intend to gain access to the ETNG pipeline, which is south of our Central Appalachia operations. ETNG has received the approval of the Federal Energy Regulatory Commission (“FERC”) for the construction of a 32-mile lateral pipeline, called Jewell Ridge Lateral, that will transport gas from our Central Appalachia operations to ETNG’s major transportation pipeline to the south. The FERC approval is subject to certain conditions, which ETNG is working to satisfy. Jewell Ridge Lateral is expected to be in service in the summer of 2006 and will provide us with an alternate transportation route to the northeast markets we currently serve as well as access to east coast markets.

Additionally, we simultaneously purchased gas from and sold gas to other counterparties between the segmentation and interruptible pools on the Columbia pipeline in order to satisfy obligations to certain customers. In accordance with EITF 99-19, we have increased our revenues and our costs. Sales of purchased gas volumes have increased primarily due to CNX Gas utilizing higher levels of firm transportation throughout the 2005 period that required us to purchase from and sell to other counterparties. CNX Gas began to enter into this type of transaction in May of 2004.

	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		28.7		17.5		11.2	64.0	%
Average Sales Price (per mcf)	$	9.59	$	6.39	$	3.20	50.1	%

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Other income consists of royalty income, third party gathering revenue and other miscellaneous income:

	2005		2004		Dollar Variance		Percentage Change
Royalty Income	$	8,158	$	5,726	$	2,432	42.5	%
Third Party Gathering Revenue		1,110		1,109		1	0.1	%
Interest Income		418		—		418	100.0	%
Other Miscellaneous		173		81		92	113.6	%
Total Other Income	$	9,859	$	6,916	$	2,943	42.6	%

Royalty income increased in 2005 compared to 2004 due to increased gas prices and additional production on existing contracts. Royalty income received from third parties is calculated as a percentage of the third parties sales price.

Third party gathering revenue is flat due to the net effect of higher volumes transported through gathering systems, offset by reduced rates in 2005 compared to 2004.

Interest income increased $418 in 2005 as a result of CNX Gas retaining cash collections as a separate stand alone company. In 2004 CNX Gas was part of CONSOL Energy’s securitization program and retained no cash resulting in zero interest income.

Other Miscellaneous consisted of additional income from miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs and Expenses

Increased costs and expenses in 2005 were impacted by purchased gas, increased firm transport, higher prices resulting in higher royalties and higher administrative expense and are made up of the following components:

	2005		2004		Dollar Variance			Percentage Change
Costs and Expenses:
Lifting Costs	$	26,794	$	23,939	$	2,855		11.9	%
Gathering and Compression Costs		40,623		37,021		3,602		9.7	%
Royalty		36,641		32,914		3,727		11.3	%
Purchased Gas Costs		278,720		113,063		165,657		146.5	%
Other		21,147		16,274		4,873		29.9	%
Equity in (Earnings) Loss of Affiliates		149		2,423		(2,274	)	(93.9	)%
Selling, General & Administrative		7,596		6,327		1,269		20.1	%
Depreciation, Depletion & Amortization		35,039		32,889		2,150		6.5	%
Interest Expense		14		—		14		100.0	%
Total Costs and Expenses	$	446,723	$	264,850	$	181,873		68.7	%

	2005		2004		Variance			Percentage Change
Produced Gross Sales Volumes (Bcf)		54.7		55.3		(0.6	)	(1.1	)%
Average Lifting Costs (per mcf)	$	0.49	$	0.43	$	0.06		14.0	%

Lifting costs per unit sold increased $0.06 per mcf in the period, of which $0.03 per mcf was due to higher production taxes in 2005 compared to 2004 driven by higher realized sales price. Well maintenance fees

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increased $0.02 per mcf due to additional wells being serviced in the current year. Various other transactions, none of which were individually material, also contributed to the increase in per unit costs.

	2005		2004		Variance			Percentage Change
Produced Gross Sales Volumes (Bcf)		54.7		55.3		(0.6	)	(1.1	)%
Average Gathering and Compression Costs (per mcf)	$	0.74	$	0.67	$	0.07		10.4	%

The increase in gathering and compression costs per unit was attributable to an additional $0.03 per mcf charge for the purchase of firm transportation capacity on the Columbia interstate pipeline because of potential curtailments on portions of shipment capacity allocated to CNX Gas as a result of increased demand for pipeline access in the 2005 period. CNX Gas began to purchase firm transportation capacity on the pipeline in May 2004. Gathering and compression costs per unit also increased approximately $0.02 per mcf due to additional power expense, as a result of converting several compressors from gas powered to electric powered in the current year. Gathering and compression unit costs also increased due to various other transactions, none of which were individually material.

CNX Gas royalty expense increased as a result of the 19.0% increase in the average gas sales price received.

In connection with the purchase of firm transportation capacity on the Columbia pipeline, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. CNX Gas believes this type of transaction may continue as a result of increased capacity demands on the Columbia pipeline. The 2004 period included a smaller volume of firm transportation activity as CNX Gas did not begin to purchase this capacity until May of 2004. Purchased gas cost information is as follows:

	2005		2004		Variance		Percentage Change
Purchased Gas Cost Volumes (Bcf)		28.7		17.5		11.2	64.0	%
Average Purchased Gas Costs (per mcf)	$	9.71	$	6.45	$	3.26	50.5	%

Other costs and expenses increased due to the following items:

	2005		2004			Dollar Variance			Percentage Change
Imbalance	$	899	$	(266	)	$	1,165		438.0	%
Direct Administration		8,053		7,280			773		10.6	%
Well Site General Maintenance		3,229		3,135			94		3.0	%
Gob Collection Costs		3,280		3,401			(121	)	(3.6	)%
Accounts Receivable Securitization Fees		1,328		1,964			(636	)	(32.4	)%
Miscellaneous		4,358		760			3,598		473.4	%
Total Other Costs and Expenses	$	21,147	$	16,274		$	4,873		29.9	%

The gas imbalance has shifted from an over-delivered position in 2004 to an under-delivered position in 2005, and therefore resulted in expense for 2005 compared to income in 2004. Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CNX Gas is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. This increase in imbalance cost was offset by corresponding increases in gas sales revenue.

Direct administration costs increased in the 2005 period due to additional staffing needs as part of the separation of CNX Gas from CONSOL Energy.

Well site general maintenance costs increased in 2005 due to the additional wells being drilled as part of the on-going drilling program.

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Gob collection costs decreased slightly in 2005 due to the reduced number of gob wells drilled as a result of the mine incidents that occurred in the current year.

Accounts receivable securitization fees have decreased as a result of CNX Gas no longer being a part of this program as of the date of separation. Prior to separation, CNX Gas sold eligible receivables to a CONSOL Energy subsidiary on a discounted basis. The fees above represent the discounted portion on the sale of those receivables.

Miscellaneous costs and expenses increased primarily due to additional administrative expenses as a result of CNX Gas becoming a stand alone company in 2005 that were not incurred in the prior period, as well as various other miscellaneous transactions that occurred in both periods, none of which were individually material.

Equity in (earnings) loss of affiliates improved in 2005 compared to 2004 as follows:

	2005			2004			Dollar Variance			Percentage Change
Buchanan Generation	$	287		$	915		$	(628	)	(68.6	)%
Knox Energy		(92	)		1,535			(1,627	)	(106.0	)%
Coalfield Pipeline		(46	)		(27	)		(19	)	70.4	%
Total Equity in (Earnings) Loss of Affiliates	$	149		$	2,423		$	(2,274	)	(93.9	)%

Buchanan Generation’s losses were lower in 2005 compared to 2004 primarily due to the facility being run for more megawatt hours in 2005 compared to 2004. This improvement was offset, in part, by increased fuel charges due to higher average gas sales prices in 2005 compared to 2004.

Knox Energy had earnings in 2005 compared to a loss in 2004 primarily due to production increases at the joint venture and additional service revenue. CNX Gas owns a 50% interest in this joint venture. CNX Gas’ production percentage increased due to a settlement agreement between CNX Gas and our partner in the joint venture in which CNX Gas now fully owns more wells. Prior to the settlement agreement, CNX Gas shared ownership interest in these wells proportionately with our partner.

Equity in earnings of Coalfield Pipeline improved in 2005 compared to 2004 due primarily to increased volumes transported through its gathering system.

Selling, general and administrative increased to $7,596 in 2005 from $6,327 in 2004 primarily due to higher charges for legal fees, accounting fees, payroll processing and other service costs. Additional costs have been incurred as a result of the separation of CNX Gas from CONSOL Energy.

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

	2005		2004		Dollar Variance		Percentage Change
Production	$	23,531	$	22,353	$	1,178	5.3	%
Gathering		11,508		10,536		972	9.2	%
Total Depreciation, Depletion and Amortization	$	35,039	$	32,889	$	2,150	6.5	%

The increase in production related depreciation, depletion and amortization was primarily due to a slightly higher unit-of-production rate in 2005 compared to 2004. Rates are generally calculated using the net book value of assets at the end of the year divided by proven developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets coming on line in 2005.

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Interest expense relates to charges for activity on the $200 million credit facility established in October of 2005.

Income Taxes

	2005			2004			Variance			Percentage Change
Earnings Before Income Taxes	$	166,718		$	132,686		$	34,032		25.6	%
Tax Expense	$	64,550		$	51,898		$	12,652		24.4	%
Effective Income Tax Rate		38.7	%		39.1	%		(0.4	)%

CNX Gas’ effective tax rate decreased in 2005 primarily due to a special deduction provided by the American Jobs Creation Act of 2004.

Twelve Months Ended December 31, 2004 compared with Twelve Months Ended December 31, 2003 (Amounts reported in thousands)

Net Income

Net income changed primarily due to the following items:

	2004		2003		Dollar Variance			Percentage Change
Revenue and other Income:
Outside Sales	$	256,579	$	178,326	$	78,253		43.9	%
Related Party Sales		22,036		32,572		(10,536	)	(32.3	)
Purchased Gas Sales		112,005		—		112,005		100.0
Other Income		6,916		4,485		2,431		54.2
Total Revenue and Other Income		397,536		215,383		182,153		84.6
Costs and Expenses:
Lifting Costs		23,939		20,761		3,178		15.3
Gathering and Compression Costs		37,021		28,914		8,107		28.0
Royalty		32,914		24,200		8,714		36.0
Purchased Gas Costs		113,063		—		113,063		100.0
Other		16,274		21,771		(5,497	)	(25.2	)
Equity in (Earnings) Loss of Affiliates		2,423		2,932		(509	)	(17.4	)
Selling, General & Administrative		6,327		3,194		3,133		98.1
Depreciation, Depletion & Amortization		32,889		33,600		(711	)	(2.1	)
Total Cost and Expenses		264,850		135,372		129,478		95.6
Earnings Before Income Taxes & Cumulative Effect of Change in Accounting Principle		132,686		80,011		52,675		65.8
Income Taxes		51,898		31,202		20,696		66.3
Earnings Before Cumulative Effect of Change in Accounting		80,788		48,809		31,979		65.5
Cumulative Effect of Change in Accounting		—		2,905		(2,905	)	(100.0	)
Net Income	$	80,788	$	51,714	$	29,074		56.2	%

Net income for 2004 was improved primarily due to increased production and increased average sales prices for gas. The increased revenues were offset, in part, by higher cost of goods sold attributable to higher sales volumes of gas and to higher unit costs for gas produced. Higher cost of gas produced was primarily attributable to increased royalty cost and cost of firm transportation incurred by the gas operations.

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Revenue and Other Income

Revenue and other income increased due to the following items:

	2004		2003		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	256,579	$	178,326	$	78,253		43.9	%
Related Party Sales		22,036		32,572		(10,536	)	(32.3	)
Purchased Gas Sales		112,005		—		112,005		100.0
Other Income		6,916		4,485		2,431		54.2
Total Revenue and Other Income	$	397,536	$	215,383	$	182,153		84.6	%

The increase in gas sales revenue, both outside and related party combined, was primarily due to a higher average sales price per mcf and increased volumes sold in 2004 compared to 2003.

	2004		2003		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		55.3		50.7		4.6	9.1	%
Average Sales Price (per mcf)	$	5.04	$	4.16	$	0.88	21.2	%

We believe that the 2004 gas market price increases were largely driven by continued concerns about declining North American gas production, as well as increased oil prices and the economic recovery which resulted in greater electricity use in our principal markets. 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. These gas swap transactions exist parallel to the underlying physical transactions. In 2004, these cash flow hedges represented 28% of our produced sales volumes at an average price of $5.10 per mcf. At year end, we intend these transactions to cover approximately 17% of our estimated 2005 production volume. CNX Gas sold 84% of its gas sales volumes for the twelve months ended December 31, 2004 under fixed priced contracts at an average price of $4.96 per mcf compared to 90% of its gas sales volumes under fixed price contracts for the twelve months ended December 31, 2003 at an average of $3.99 per mcf. Higher sales volumes in 2004 were a result of wells coming on line from the ongoing drilling program, which allowed CNX Gas to take advantage of increased prices.

Due to the anticipated curtailment in the shipment capacity allocated to CNX Gas as a result of increased demand for pipeline use on the Columbia interstate pipeline, CNX Gas purchased firm transportation capacity on the pipeline. The first firm transportation agreement covered the May 2004 through October 2004 period. In November 2004, CNX Gas entered into an extended firm transportation agreement for use on the pipeline. This agreement covered the November 2004 through October 2006 period and assured pipeline capacity of approximately 20% of our projected production for the same period. In addition, in connection with the purchase of firm transportation capacity on Columbia’s pipeline, we purchased gas from and sold gas to other gas suppliers, which increased our revenues and our costs.

	2004		2003	Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		17.5	—		17.5	100.0	%
Average Sales Price (per mcf)	$	6.39	—	$	6.39	100.0	%

Other income consists of royalty income, third party gathering revenue and other miscellaneous income.

	2004		2003		Dollar Variance		Percentage Change
Royalty Income	$	5,726	$	3,967	$	1,759	44.3
Third Party Gathering Revenue		1,109		440		669	152.0
Other Miscellaneous		81		78		3	3.8
Total Other Income	$	6,916	$	4,485	$	2,431	54.2	%

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Royalty income increased in 2004 compared to 2003 due to increased gas prices and additional contracts being initiated. Royalty income received from third parties is calculated as a percentage of the third parties’ sales price.

Third party gathering revenue has increased due to higher volumes transported through gathering systems for third parties in 2004 compared to 2003. The increased volumes are attributable to volumes of gas moved on behalf of two additional parties through CNX Gas’ gathering systems to Columbia’s interstate gas pipeline.

Other income increased for 2004 due to miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs and Expenses

Increased cost of goods sold and other charges in 2004 and 2003 were made up of the following components:

	2004		2003		Dollar Variance			Percentage Change
Cost of Goods Sold and Other Charges:
Lifting Costs	$	23,939	$	20,761	$	3,178		15.3	%
Gathering and Compression Costs		37,021		28,914		8,107		28.0
Royalty		32,914		24,200		8,714		36.0
Purchased Gas Costs		113,063		—		113,063		100.0
Other		16,274		21,771		(5,497	)	(25.2	)
Equity in (Earnings) Loss of Affiliates		2,423		2,932		(509	)	(17.4	)
Selling, General & Administrative		6,327		3,194		3,133		98.1
Depreciation, Depletion & Amortization		32,889		33,600		(711	)	(2.1	)
Total Cost and Expenses	$	264,850	$	135,372	$	129,478		95.6	%

Increased gas production costs were due to increased sales volumes and increased unit costs.

	2004		2003		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		55.3		50.7		4.6	9.1	%
Average Lifting Costs (per mcf)	$	0.43	$	0.41	$	0.02	4.9	%

Gas production costs per unit sold were higher in 2004 compared to 2003 due to increased severance tax charges. Severance taxes are calculated as 3% of gas sales price. Due to the 21.2% average sales price increase, severance taxes have increased approximately $0.03 per mcf. The increased severance taxes were offset, in part, by reduced well-head maintenance costs. Maintenance costs were lower in 2004 compared to 2003 due mainly to the timing of the completion of work.

Gathering and compression costs increased due primarily to increased unit costs and increased sales volumes.

	2004		2003		Variance		Percentage Change
Production Gross Sales Volumes (Bcf)		55.3		50.7		4.6	9.1	%
Average Gathering and Compression Costs (per mcf)	$	0.67	$	0.57	$	0.10	17.5	%

The increase in gathering and compression costs per unit were primarily due to approximately $0.08 per mcf increase related to the purchase of firm transportation capacity on the Columbia pipeline because of potential curtailments on portions of the shipment capacity allocated to CNX Gas as a result of increased demand for

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pipeline transportation capacity. CNX Gas purchased firm transportation capacity on the pipeline from the May 2004 through October 2004 period to assure firm pipeline capacity of our projected production. In November 2004, CNX Gas entered into an extended firm transportation agreement with Columbia’s pipeline. This arrangement covers November 2004 through October 2006. The purchased firm transportation capacity on the pipeline represents approximately 20% of our projected production for the same period. Increased unit costs were also due to third party consulting fees related to the treatment equipment that removes carbon dioxide from the gas stream. The treatment equipment was put into production in February 2004 and took several months to become fully integrated into CNX Gas’ gathering system.

Royalty costs increased primarily due to the 21.2% increase in average sales price per mcf in 2004 compared to 2003.

In connection with the purchase of firm transportation capacity on Columbia’s pipeline, we purchased from and sold to other gas suppliers, which increased our revenues and our costs. CNX Gas believes this type of transaction may continue as a result of increased capacity demands on the Columbia pipeline. Purchased gas cost information is as follows:

	2004		2003	Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		17.5	—		17.5	100.0	%
Average Cost Per Thousand cubic feet (per mcf)	$	6.45	—	$	6.45	100.0	%

Other costs and expenses decreased due to the following items:

	2004		2003		Dollar Variance			Percentage Change
Well Site General Maintenance	$	3,135	$	2,049	$	1,086		53.0	%
Accounts Receivable Securitization Fees		1,964		1,103		861		78.1
Land Rental Fees		534		1,003		(469	)	(46.8	)
Well Plugging Accretion Expense		525		450		75		16.7
Legal Settlements		—		5,728		(5,728	)	(100.0	)
Miscellaneous		10,116		11,438		(1,322	)	(11.6	)
Total Other Cost	$	16,274	$	21,771	$	(5,497	)	(25.2	)%

Well site general maintenance costs increased in 2004 due to the additional wells being drilled as part of our on-going drilling program.

Accounts receivable securitization fees have increased due to higher accounts receivable balances being sold to a subsidiary of CONSOL Energy, our principal stockholder, in 2004 compared to 2003. Higher accounts receivable balances available for sale were attributable to higher average sales prices and volumes in the period to period comparison. CNX Gas sells eligible receivables to CONSOL Energy’s subsidiary on a discounted basis. The fees above represent the discount portion on the sale of the receivables. CNX Gas discontinued this type of transaction with CONSOL Energy in connection with the separation of the companies.

Land rental fees decreased in 2004 attributable to new agreements being put into place that allow fees to be recoupable against royalties owed. Prior period agreements did not include the recoupable feature.

Well plugging accretion expense increased in 2004 compared to 2003 due to higher well plugging liabilities, which increased due to additional wells being drilled.

Legal settlements in 2003 were related to a settlement paid for a royalty dispute. The claim alleged that CNX Gas calculated royalties owed to certain lessors using components that were not consistent with the agreement.

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Pursuant to the court-ordered settlement, CNX Gas paid the difference between CNX Gas’ calculation and the court-approved calculation for royalties on gas production from September 1999 to December 2002.

Miscellaneous costs and expenses decreased due to various miscellaneous transactions that occurred in both periods, none of which were individually material. The decrease in miscellaneous costs was offset, in part, by an increase of $274 in direct administrative costs related to gas operations. The increase in direct administrative costs was primarily attributable to an increase in staffing levels.

Equity in (earnings) loss of affiliates were lower in 2004 compared to 2003 due to the following:

	2004			2003		Dollar Variance			Percentage Change
Buchanan Generation	$	915		$	1,173	$	(258	)	(22.0	)%
Knox Energy		1,535			1,644		(109	)	(6.6	)
Coalfield Pipeline		(27	)		115		(142	)	(123.5	)
Total Equity in Loss of Affiliates	$	2,423		$	2,932	$	(509	)	(17.4	)%

Buchanan Generation’s losses were lower in 2004 compared to 2003 primarily due to the unit being run for more megawatt hours in 2004 compared to 2003. This improvement was offset, in part, by increased fuel charges due to higher average gas sales prices in 2004 compared to 2003.

Knox Energy losses were lower in 2004 compared to 2003 primarily due to production increases at the joint venture. The CNX Gas portion of the joint venture production was approximately 230 mmcf in 2004 compared to approximately 93 mmcf in 2003. CNX Gas owns a 50% interest in this joint venture.

Equity in earnings of Coalfield Pipeline improved in 2004 compared to 2003 due primarily to increased volumes transported through their gathering system.

Selling, general and administrative costs have increased to $6,327 in 2004 from $3,194 in 2003, primarily due to higher charges for legal fees, accounting fees, payroll processing and other service costs.

Depreciation, depletion and amortization has decreased due to the following items:

	2004		2003		Dollar Variance			Percentage Change
Production	$	22,353	$	23,424	$	(1,071	)	(4.6	)%
Gathering		10,536		10,176		360		3.5
Total Depreciation, Depletion and Amortization	$	32,889	$	33,600	$	(711	)	(2.1	)%

Depreciation, depletion and amortization was consistent in both 2004 and 2003. Production assets are depreciated using the units of production method. Units of production depreciation was based on higher gas volumes, offset by a lower rate due to increased reserve figures at January 1, 2004 compared to January 1, 2003. Gathering assets are depreciated using the straight-line method and did not materially change in the period-to- period comparison.

Income Taxes

	2004			2003			Variance			Percentage Change
Earnings Before Income Taxes	$	132,686		$	80,011		$	52,675		65.8	%
Tax Expense	$	51,898		$	31,202		$	20,696		66.3	%
Effective Income Tax Rate		39.1	%		39.0	%		0.1	%

CNX Gas’ effective tax rate was consistent in 2004 and 2003.

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Cumulative Effect of Changes in Accounting for Gas Well Plugging Costs

Effective January 1, 2003, CNX Gas adopted SFAS No. 143 as required. CONSOL Energy reflected a gain of $2,905, net of a tax cost of approximately $1,879. At the time of adoption, total assets, net of accumulated depreciation, increased approximately $2,085 and total liabilities decreased approximately $2,699. The amounts recorded upon adoption are 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.

Previous accounting standards generally used the units-of-production method to match estimated retirement costs with the revenues generated by the producing assets. In contrast, SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines. Because of the long lives of the underlying producing assets, the impact on net income in the near term is not expected to be material.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States 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.

Other Post Employment Benefits

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 medical and life benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of $1,000 per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include 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 post employment benefit plan in 2006. CNX Gas expects to pay benefit claims as they become due.

Various actuarial assumptions, including discount rate, expected trend in health care costs, average remaining service period, average remaining life expectancy and per capita costs, are used by CONSOL Energy’s independent actuary to estimate the cost and benefit obligations for our retiree health plans. The discount rate is determined each year at the measurement date (currently September 30). The discount rate is an estimate of the current interest rate at which the Other Post Employment Benefit liabilities could be effectively settled at the measurement date. In estimating this rate, CONSOL Energy looks to rates of return on high-quality, fixed-income investments that receive one of the two highest ratings given by a recognized ratings agency. For the year ended December 31, 2005 and 2004, the discount rate used to calculate the period end liability and the following year’s expense was 5.75% and 6.00%, respectively.

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Salaried Pensions

As of December 31, 2005, CNX Gas participates in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The pension benefit obligation earned by salaried CNX Gas employees prior to the date of separation from CONSOL Energy remains with CONSOL Energy. As of the date of separation, any incremental pension liability earned by CNX Gas salaried employees is the obligation of CNX Gas. The benefits for this plan are based primarily on years of service and employees’ compensation near retirement. Effective January 1, 2006, an amendment was made to the CONSOL Energy Inc. Employee Retirement Plan that suspended all service accruals of gas employees in this plan. In its place, an identical plan was created sponsored by CNX Gas to provide a benefit for all service accruals going forward.

Reserve Estimates

Our estimates of proved natural gas reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. 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.

Successful Efforts Accounting

We are required to select among alternative acceptable accounting policies. There are two generally acceptable methods for accounting for oil and gas producing activities. The full-cost method allows the capitalization of all costs associated with exploring for, acquiring and developing oil and natural gas reserves. The successful efforts method allows only for the capitalization of costs directly associated with exploring for, acquiring and developing proven natural gas properties. Costs related to exploration that are not successful are expensed when it is determined that commercially productive gas reserves were not found. We have elected to use the successful efforts method to account for our gas producing activities.

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.

Deferred Taxes

CNX Gas accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2005, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $38

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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.

Well Plugging Obligations

SFAS No. 143 requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Asset retirement obligations relate to the closure of gas wells upon exhaustion of gas reserves. Changes in the variables used to calculate the liabilities can have a significant effect on the gas well closing liabilities. The amounts of assets and liabilities recorded are dependent upon a number of variables, including the estimated future retirement costs, estimated proven reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

SFAS No. 143 requires depreciation of the capitalized asset retirement cost and accretion of the asset retirement obligation over time. The depreciation will generally be determined on a units-of-production basis, whereas the accretion to be recognized will escalate over the life of the producing assets, typically as production declines.

Liquidity and Capital Resources

We intend to satisfy our future working capital requirements and fund our capital expenditures with cash from operations and our recently entered into $200 million credit facility. CNX Gas entered into a new credit agreement dated as of October 7, 2005, which is described in more detail below, with a group of commercial lenders. The new credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200 million (with the ability to request an increase in the aggregate outstanding principal amount up to $300 million), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital.

CNX Gas and our subsidiaries had guaranteed CONSOL Energy’s $750 million revolving credit facility and 7.875% notes due March 1, 2012 in the principal amount of approximately $250 million. In addition, the assets of CNX Gas’ subsidiaries as well as substantially all of the assets being contributed to CNX Gas by CONSOL Energy were subject to liens securing this revolving credit facility, the 7.875% notes and CONSOL Energy’s 8.25% medium term notes due 2007 in the principal amount of approximately $45 million. Lastly, the principal gas subsidiary participated and sold receivables in CONSOL Energy’s $125 million receivables facility. CONSOL Energy obtained the release of CNX Gas and our subsidiaries from these guarantees in connection with the separation of the companies as well as the release of these liens on the assets of the CNX Gas subsidiaries and the other assets being contributed to CNX Gas and terminated the participation of the principal gas subsidiary in CONSOL Energy’s receivables facility. Although released from the existing guarantee of the 7.875% notes, the indenture for the 7.875% notes requires CNX Gas to guarantee the 7.875% notes if CNX Gas entered into borrowing arrangements with one or more third parties (excluding CONSOL Energy). As a result of entering into our new $200 million credit agreement with third party commercial lenders, we and our subsidiaries executed a supplemental indenture and are guarantors of the 7.875% notes. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture and the agreement governing the 8.25% medium term notes would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes. CONSOL Energy has advised us that, in accordance with its previously stated intention, CONSOL Energy sought to obtain an amendment to its indenture for the 7.875% notes in order to obtain the release of CNX Gas and our subsidiaries as guarantors of the 7.875% notes. Based on its discussions with a number of the note holders, CONSOL Energy has determined that, at this time, it cannot obtain an amendment of the indenture on commercially acceptable terms. Therefore, CONSOL Energy will not formally solicit the 7.875% note holders for the release and, consequently, we will remain guarantors of the 7.875% notes.

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We believe that cash generated from operations and borrowings under our new credit facility will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major acquisitions), and to provide required financial resources. Nevertheless, our ability to satisfy our working capital requirements or fund planned capital expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the gas industry and other financial and business factors, some of which are beyond our control.

We have also entered into various gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net loss of $34.4 million (net of $22.3 million of deferred tax) at December 31, 2005. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings for the twelve months ended December 31, 2005.

Cash Flows

	2005 Year to Date			2004 Year to Date			Change
Cash provided by operating activities	$	144,997		$	175,350		$	(30,353	)
Cash used in investing activities	$	(108,287	)	$	(93,114	)	$	(15,173	)
Cash used in financing activities	$	(16,640	)	$	(82,237	)	$	65,597

CNX Gas is no longer part of CONSOL Energy’s accounts receivable securitization program, which historically resulted in a quick turnaround. The receivables we generate now remain with CNX Gas, and the cash is collected in each subsequent month.

Contractual Commitments

The following is a summary of our significant contractual obligations at December 31, 2005 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, related to these items at December 31, 2005 to be as follows:

(In thousands)	Within 1 Year		1-3 Years		3-5 Years		More than 5 Years		Total
Long Term Debt Obligations	$	—	$	—	$	—	$	—	$	—
Capital (Finance) Lease Obligations		3,658		12,753		11,173		39,506		67,090
Operating Lease Obligations		372		380		257		905		1,914
Other Long-Term Liabilities:
Gas Firm Transportation Obligation		2,847		4,621		4,621		3,856		15,945
Other Liabilities (a)		—		—		—		12,096		12,096
Well Plugging Liabilities		378		756		756		9,018		10,908
Pension		1		8		35		175		219
Postretirement Benefits Other than Pension		5		44		104		3,215		3,368
Total Contractual Obligations	$	7,261	$	18,562	$	16,946	$	68,771	$	111,540

(a) This item represents legal contingencies reflected on the balance sheet for potential settlements of the two cases referenced in Note 18 of our annual financial statements. Due to the uncertainty surrounding these settlements, it is difficult to predict if and when a payout may take place.

As discussed in “Critical Accounting Policies” and in the Notes to our Consolidated Financial Statements included in this Annual Report, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.

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Moreover, in particular, for periods after 2005 our estimates may change from the amounts included in the table, and may change significantly, if our assumptions change to reflect changing conditions.

$200 Million Credit Facility.

We and our wholly-owned subsidiaries entered into a new credit agreement dated as of October 7, 2005 with a group of commercial lenders. The new credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200 million (with the ability to request an increase in the aggregate outstanding principal amount up to $300 million), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. In connection with the closing of the credit agreement, a $50 million intercompany credit agreement with CONSOL Energy was terminated.

Our ability to borrow and obtain letters of credit under the new credit agreement is generally limited to a borrowing base. The required number of lenders will determine this borrowing base by calculating a loan value of CNX Gas’ proved reserves and reducing that number by an equity cushion determined by these lenders.

Interest on outstanding indebtedness under the credit agreement currently accrues, at our option, at a rate based on either: (A) the greater of (i) the lead bank’s prime corporate lending rate and (ii) the federal funds open rate plus 0.5%, in each case, plus a margin ranging from 0% to 0.25%, or (B) the LIBOR rate plus a margin ranging from 1.00% to 1.75%. The applicable margin added to the underlying interest rate fluctuates based on the aggregate outstanding principal under the credit agreement with the margin increasing as the outstanding principal amount increases.

The new credit agreement matures on October 7, 2010, and requires compliance with conditions precedent that must be satisfied prior to any borrowing as well as ongoing compliance with certain affirmative and negative covenants to which CNX Gas and its wholly-owned subsidiaries must adhere. The affirmative covenants include (i) maintenance of existence, (ii) payment of obligations, including taxes, (iii) maintenance of properties, insurance, intellectual property and books and records, (iv) compliance with laws, leases, pipeline arrangements and other material contractual obligations, (v) use of proceeds, (vi) subordination of intercompany loans and (vii) access to title information. The negative covenants include, without limitation, restrictions (in each case with certain limited exceptions unless otherwise noted) on the ability of CNX Gas and its wholly-owned subsidiaries to:

• create, incur, assume or suffer to exist any indebtedness;

• create or permit to exist liens on its properties;

• guaranty the debt of another party except in certain circumstances (which exception includes our guarantee of CONSOL Energy’s $250 million 7.875% notes due 2012);

• merge with or into another person, liquidate or dissolve; or acquire all or substantially all of the assets of any going concern or going line of business or acquire all or a substantial portion of another person’s assets (other than similar lines of business for total consideration below specified amounts);

• make particular investments and loans;

• sell, transfer, convey, assign or dispose of its assets or properties other than in the ordinary course of business and other select instances;

• deal with any affiliate except in the ordinary course of business on terms no less favorable to us than we would otherwise receive in an arm’s length transaction;

• other than CNX Gas, issue additional equity to any person other than CNX Gas or its wholly-owned subsidiaries;

• amend in any material manner its certificate of incorporation, bylaws, or other organizational documents;

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• enter into an agreement that prohibits the granting of a lien on our property or the property of any of our wholly-owned subsidiaries;

• enter into any hedging agreement other than those permitted by the credit agreement in the ordinary course of our business; or

• voluntarily sell, pool or unitize its proved reserves.

The new credit agreement also requires us to maintain certain financial ratios calculated as of the end of each fiscal quarter: the ratio of outstanding indebtedness (less cash on hand) to consolidated earnings before interest, taxes, depreciation and amortization is required to be equal to or less than three to one and the ratio of consolidated earnings before interest, taxes, depreciation and amortization to consolidated cash interest expense is required to be equal to or greater than three to one. The new credit agreement also contains customary events of default, including a cross-default to certain other debt, breaches of representations and warranties, change of control events and breaches of covenants.

In addition, the new credit agreement restricts our ability to make or pay dividends or distributions to our stockholders. We cannot make or pay dividends or distributions to our stockholders unless (i) the aggregate amount does not exceed fifty percent of our consolidated net income from the preceding four quarters and (ii) at the time of payment after giving effect thereto, our outstanding indebtedness (less cash on hand) is less than or equal to our consolidated earnings before interest, taxes, depreciation and amortization, and our outstanding borrowings under the credit agreement do not exceed 75 percent of the then current total availability under the facility or the borrowing base (whichever is less) and no default or potential default exists.

Our obligations under the new credit agreement are not secured by a lien on any of our assets. Our wholly-owned subsidiaries guaranteed our obligations.

Off-Balance Sheet Arrangements

We do not maintain any off-balance sheet transactions, arrangements, obligations or other relationships with unconsolidated entities or others that are likely to have a material current or future effect on our condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources which are not disclosed in the notes to the consolidated financial statements.

Recent Accounting Pronouncements

In September 2005, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for transactions that CNX Gas considers matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. CNX Gas is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements; however, management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.

In June 2005, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 154, Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3.

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This Statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This Statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by this Statement. This Statement shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We do not expect this guidance to have a significant impact on CNX Gas.

In April 2005, the FASB issued FSP No. FAS 19-1 “Accounting for Suspended Well Costs” (FSP 19-1). This position concluded that exploratory well costs should continue to be capitalized beyond twelve months when the well has found a sufficient quantity of reserves to justify its completion as a producing well, and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This guidance requires management to exercise more judgment than was previously required and also requires additional disclosure. Management does not believe this statement of position will have a significant effect on the financial statements.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 47, Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143. This interpretation clarifies that the term, conditional asset retirement obligation, as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred, generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS No. 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. We do not expect this guidance to have a significant impact on CNX Gas.

On December 15, 2004, the FASB released its final revised standard entitled FASB Statement No. 123R, “Share-Based Payment” (SFAS No.123R). This Statement requires that all public entities measure the cost of equity-based service awards based on the grant-date fair value. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award or the requisite service period, which usually is the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service. In addition, the SEC Staff issued Staff Accounting Bulletin (SAB) 107 on SFAS No. 123R in March 2005. The SAB was issued to assist preparers by simplifying some of the implementation challenges of SFAS No. 123R while enhancing information that investors receive. This SAB provides guidance related to, among other relevant items, share-based payment transactions with non-employees, valuation methods, the classification of compensation expense, non-GAAP financial measures, first-time adoptions of SFAS No.123R in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects, the modification of employee share options prior to adoption of SFAS No. 123R, and disclosures in Management’s Discussion and Analysis subsequent to adoption of SFAS No. 123R. SFAS No.123R is to be effective for public companies as of the beginning of the first annual reporting period that begins after June 15, 2005. CNX Gas will implement SFAS No. 123R on January 1, 2006, as required. The expected impact of unvested stock options outstanding at December 31, 2005,

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under the modified prospective application, is approximately a $1.4 million reduction to earnings before income taxes for the year ended December 31, 2006. Management is currently evaluating the policy for determining our windfall tax benefits.

In October 2004, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-10, “Applying Paragraph 19 of FASB Statement No. 131, ‘Disclosure about Segments of an Enterprise and Related Information,’ in Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds” (EITF 04-10). FASB Statement No. 131 requires that a public business enterprise report financial and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. EITF 04-10 clarifies how an enterprise should evaluate the aggregation criteria in paragraph 17 of FAS No. 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of FAS No. 131. In addition, the FASB Task Force has requested that the FASB staff propose a FASB Staff Position (FSP) to provide guidance in determining whether two or more operating segments have similar economic characteristics. The Task Force has agreed that since the two issues are interrelated, the effective date of EITF 04-10 should coincide with the future undetermined effective date of the anticipated FSP. We are currently evaluating the positions addressed in EITF 04-10, and foresee no significant changes in the reporting practices currently used to report segment information.

In October 2004, the American Jobs Creation Act of 2004 was signed into law. CNX Gas has implemented the qualified production activities deduction as enacted by the American Jobs Creation Act of 2004. The deduction is currently equal to 3% of qualified production activities income as limited by taxable income and as limited by 50 percent of the employer’s W-2 wages for the tax year. The percentage used in computing the deduction will be 3% in 2006, 6% in 2007 through 2009 and 9% in 2010 and after. As a special deduction in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” it is included as a permanent benefit in our estimate of our annual effective tax rate.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

In addition to the risks inherent in our operations, CNX Gas is exposed to financial, market, political and economic risks. The following discussion provides additional detail regarding CNX Gas’ exposure to the risks of changing natural gas prices.

CNX Gas uses fixed-price contracts and derivative commodity instruments that qualify as cash-flow hedges under Statement of Financial Accounting Standards No. 133, as amended, to minimize exposure to market price volatility in the sale of natural gas. Our risk management policy strictly prohibits the use of derivatives for speculative positions.

CNX Gas has established risk management policies and procedures to strengthen the internal control environment of the marketing of commodities produced from our asset base. All of the derivative instruments are held for purposes other than trading. They are used primarily to reduce uncertainty and volatility and cover underlying exposures. CNX Gas’ market risk strategy incorporates fundamental risk management tools to assess market price risk and establish a framework in which management can maintain a portfolio of transactions within pre-defined risk parameters.

CNX Gas believes that the use of derivative instruments along with the risk assessment procedures and internal controls does not expose CNX Gas to material risk. However, the use of derivative instruments without other risk assessment procedures could materially affect CNX Gas’ results of operations depending on interest rates, exchange rates or market prices. Nevertheless, we believe that use of these instruments will not have a material adverse effect on our financial position or liquidity.

For a summary of accounting policies related to derivative instruments, see Note 1 of the notes to the consolidated annual financial statements included in this Annual Report.

Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2005 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2005 are provided in the following table:

	Incremental Decrease Assuming a Hypothetical Price Decrease of:
	10%		25%
	(In millions)
Pre-Tax Income (1)	$	34.4	$	75.5

(1) CNX Gas remains at risk for possible changes in the market value of these derivative instruments; however, such risk should be reduced by price changes in the underlying hedged item. The effect of this offset is not reflected in the sensitivity analyses. CNX Gas entered into derivative instruments to convert the market prices related to portions of the 2005 through 2008 anticipated sales of natural gas to fixed prices. The sensitivity analyses reflect an inverse relationship between increases in commodity prices and a benefit to earnings. When commodity prices increase, pretax income decreases. As of December 31, 2005, the fair value of these contracts was a net loss of $34.4 million (net of $22.3 million deferred tax). We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

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Hedging Volumes

As of December 31, 2005, 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
2006 Fixed Price Volumes
Hedged mcf		3,654,822		4,619,289		4,670,051		4,050,761		16,994,923
Weighted Average Hedge Price/mcf	$	6.88	$	7.73	$	7.73	$	7.21	$	7.42
2007 Fixed Price Volumes
Hedged mcf		1,827,411		1,847,717		1,868,020		1,868,020		7,411,168
Weighted Average Hedge Price/mcf	$	7.67	$	7.67	$	7.67	$	7.67	$	7.67
2008 Fixed Price Volumes
Hedged mcf		1,847,716		1,847,716		1,868,020		1,868,020		7,431,472
Weighted Average Hedge Price/mcf	$	7.20	$	7.20	$	7.20	$	7.20	$	7.20

CNX Gas is exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is subject to continuing review.

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Financial Statements for the Twelve Months Ended December 31, 2005, 2004 and 2003
Report of Independent Registered Public Accounting Firm	63
Consolidated Statements of Income	64
Consolidated Balance Sheets	65
Consolidated Statements of Stockholders’ Equity	66
Consolidated Statements of Cash Flows	67
Notes to Audited Financial Statements	68

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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 accompanying consolidated balance sheets and the related consolidated statements of income, stockholders’ equity and cash flows present fairly, in all material respects, the financial position of CNX Gas Corporation and its subsidiaries (CNX Gas) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of CNX Gas’ 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.

As discussed in Note 5 to the consolidated financial statements, CNX Gas changed the manner in which it accounts for asset retirement costs as of January 1, 2003.

/s/    PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 20, 2006

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CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)

	For the Twelve Months Ended December 31,
	2005		2004		2003
Revenue and Other Income:
Outside Sales	$	322,382	$	256,579	$	178,326
Related Party Sales		6,052		22,036		32,572
Purchased Gas Sales		275,148		112,005		—
Other Income		9,859		6,916		4,485
Total Revenue and Other Income		613,441		397,536		215,383
Costs and Expenses:
Lifting Costs		26,794		23,939		20,761
Gathering and Compression Costs		40,623		37,021		28,914
Royalty		36,641		32,914		24,200
Purchased Gas Costs		278,720		113,063		—
Other		21,147		16,274		21,771
Equity in Loss of Affiliates		149		2,423		2,932
Selling, General and Administrative		7,596		6,327		3,194
Depreciation, Depletion and Amortization		35,039		32,889		33,600
Interest Expense		14		—		—
Total Costs and Expenses		446,723		264,850		135,372
Earnings Before Cumulative Effect of Change in Accounting Principle and Income Taxes		166,718		132,686		80,011
Income Taxes		64,550		51,898		31,202
Earnings Before Cumulative Effect of Change in Accounting Principle		102,168		80,788		48,809
Cumulative Effect of Change in Accounting For Gas Well Closing Costs (Net of Income Taxes of $1,879)		—		—		2,905
Net Income	$	102,168	$	80,788	$	51,714
Earnings per share:
Basic	$	0.76	$	0.66	$	0.42
Diluted	$	0.76	$	0.66	$	0.42
Weighted Average Number of Common Shares Outstanding:
Basic		134,071,334		122,896,667		122,896,667
Dilutive		134,137,219		122,988,359		122,988,359

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

64

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

	December 31,
	2005			2004
ASSETS
Current Assets:
Cash and Cash Equivalents	$	20,073		$	3
Accounts Receivable:
Trade		41,121			700
Related Party		728			—
Other		550			735
Deferred Taxes		9,339			8,301
Derivatives		—			3,766
Other Current Assets		18,067			6,585
Total Current Assets		89,878			20,090
Property and Equipment, Net		723,547			640,876
Other Assets		11,903			14,951
Investments in Equity Affiliates		49,528			47,373
TOTAL ASSETS	$	874,856		$	723,290
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	22,541		$	24,002
Accrued Royalties Payable		10,504			8,701
Accrued Severance Taxes		2,747			2,337
Accrued Income Taxes		5,518			941
Derivatives		23,777			13,027
Other Current Liabilities		21,071			6,112
Total Current Liabilities		86,158			55,120
Deferred Taxes		47,736			183,624
Other Liabilities		14,310			10,202
Well Plugging Liabilities		10,908			8,685
Derivatives		32,909			—
Postretirement Benefits Other Than Pension		3,363			3,103
Total Liabilities		195,384			260,734
Stockholders’ Equity
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,833,334 Issued and Outstanding at December 31, 2005		1,508			—
Capital in Excess of Par Value		779,509			215,710
Retained Earnings (Deficit)		(65,530	)		252,469
Accumulated Other Comprehensive Loss		(34,733	)		(5,623	)
Unearned Compensation on Restricted Stock Units		(1,282	)		—
Total Stockholders’ Equity		679,472			462,556
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	874,856		$	723,290

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

65

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 Loss			Unearned Compensation on Restricted Stock Units			Total Stockholders’ Equity
Balance at December 31, 2002	$	—	$	350,473		$	119,967		$	(1,823	)	$	—		$	468,617
Net Income		—		—			51,714			—			—			51,714
Gas Cash Flow Hedge (Net of $2,312 tax)		—		—			—			(3,573	)(a)		—			(3,573	)
Comprehensive Income (Loss)		—		—			51,714			(3,573	)		—			48,141
Return of Capital to Parent		—		(52,526	)		—			—			—			(52,526	)
Balance at December 31, 2003		—		297,947			171,681			(5,396	)		—			464,232
Net Income		—		—			80,788			—			—			80,788
Gas Cash Flow Hedge (Net of $146 tax)		—		—			—			(227	)(b)		—			(227	)
Comprehensive Income (Loss)		—		—			80,788			(227	)		—			80,561
Return of Capital to Parent		—		(82,237	)		—			—			—			(82,237	)
Balance at December 31, 2004		—		215,710			252,469			(5,623	)		—			462,556
Net Income		—		—			102,168			—			—			102,168
Gas Cash Flow Hedge (Net of $18,542 tax)		—		—			—			(29,110	)(c)		—			(29,110	)
Comprehensive Income (Loss)		—		—			102,168			(29,110	)		—			73,058
Issuance of Common Stock		1,508		418,659			—			—			—			420,167
Effect of Tax Basis Step-up		—		165,042			—			—			—			165,042
Issuance of Restricted Stock units under the Equity Incentive Plan (92,969 units)		—		1,487			—			—			(1,487	)		—
Amortization of Restricted Stock Unit Grants		—		—			—			—			205			205
Dividends paid		—		—			(420,167	)		—			—			(420,167	)
Return of Capital to Parent		—		(21,389	)		—			—			—			(21,389	)
Balance at December 31, 2005	$	1,508	$	779,509		$	(65,530	)	$	(34,733	)	$	(1,282	)	$	679,472

(a) Of the ($3,573) net change in accumulated other comprehensive income/(loss) in the period, ($7,733) represents the settlements recognized in net income.

(b) Of the ($227) net change in accumulated other comprehensive income/(loss) in the period, ($20,047) represents the settlements recognized in net income.

(c) Of the ($29,110) net change in accumulated other comprehensive income/(loss) in the period ($30,948) represents the settlements recognized in net income.

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

66

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

	For the Twelve Months Ended December 31,
	2005			2004			2003
Operating Activities:
Net Income	$	102,168		$	80,788		$	51,714
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Cumulative Effect of Change in Accounting Principle, net of tax		—			—			(2,905	)
Depreciation, Depletion and Amortization		35,039			32,889			33,600
Compensation from Restricted Stock Unit Grants		205			—			—
Income Taxes		5,650			941			—
Deferred Income Taxes		46,779			50,957			31,202
Equity in Loss of Affiliates		149			2,423			2,932
Changes in Operating Assets:
Accounts Receivable		(40,236	)		(783	)		16,576
Related Party Receivable		(728	)		—			—
Other Current Assets		(7,716	)		(6,542	)		312
Changes in Other Assets		(4,951	)		(2,367	)		(5,719	)
Changes in Operating Liabilities:
Accounts Payable		(8,936	)		2,597			13,759
Other Current Liabilities		26,119			8,672			1,407
Changes in Other Liabilities		(8,600	)		5,583			(236	)
Other		55			192			491
Net Cash Provided by Operating Activities		144,997			175,350			143,133
Investing Activities:
Capital Expenditures		(110,752	)		(89,753	)		(83,869	)
Investment in Equity Affiliates		2,465			(3,361	)		(7,169	)
Proceeds from Sales of Assets		—			—			433
Net Cash Used in Investing Activities		(108,287	)		(93,114	)		(90,605	)
Financing Activities:
Issuance of Common Stock		420,167			—			—
Dividends Paid		(420,167	)		—			—
Payments to Parent		(16,640	)		(82,237	)		(52,526	)
Net Cash Used in Financing Activities		(16,640	)		(82,237	)		(52,526	)
Net Increase (Decrease) in Cash and Cash Equivalents		20,070			(1	)		2
Cash and Cash Equivalents at Beginning of Period		3			4			2
Cash and Cash Equivalents at End of Period	$	20,073		$	3		$	4

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

67

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands)

Note 1—Significant Accounting Policies:

Nature of Operations

CNX Gas Corporation (CNX Gas) is a natural gas producer with an emphasis on Appalachian area natural gas drilling, transportation and sales. CNX Gas is one of the largest U.S. producers of CBM, and is one of the largest owners of proved gas reserves in the Appalachian Basin. CNX Gas transports gas from wells we own, and those operated by others, to interstate pipelines by way of the CSGC pipeline and the Coalfield Pipeline Company pipeline. CNX Gas finances drilling activities through existing operations.

These financial statements reflect the activities of CNX Gas. As of December 31, 2004, CNX Gas was not a legal entity and there were no outstanding shares of common stock. However, carved out financial statements were prepared in accordance with Regulation S-X Article 3 “General instructions as to financial statements” and SAB Topic 1-B1 “Costs reflected in historical financial statements” and are presented for comparative purposes. Earnings per share information is presented as if these shares were outstanding at December 31, 2004. As of January 19, 2006, CNX Gas became a publicly traded company (trading under the symbol CXG on the NYSE) operating in the energy sector.

Basis of Consolidation

The consolidated financial statements include the accounts of majority-owned and controlled subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation. The equity method of accounting is used for investments in affiliates and other joint ventures over which CNX Gas has significant influence but does not have effective control. CNX Gas also evaluates consolidation of entities under Financial Accounting Standards Board Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). FIN 46 requires management to evaluate whether an entity or interest is a variable interest entity and whether CNX Gas is the primary beneficiary. Consolidation is required if both of these criteria are met.

CNX Gas has the following investments accounted for under the equity method of accounting:

Investee	CNX Gas % Ownership
Knox Energy, LLC	50	%
Coalfield Pipeline Company	50	%
Buchanan Generation, LLC	50	%

CNX Gas has no variable interest entities.

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 well plugging liabilities, proved gas reserve estimates, deferred tax assets and liabilities and employee benefit related obligations.

Cash and Cash Equivalents

Cash management services for CNX Gas are performed by CONSOL Energy.

68

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

All cash in-flows and out–flows, as of the date of separation, are processed through CNX Gas bank accounts. However, all cash transactions prior to the date of separation were processed through CONSOL Energy bank accounts and were considered capital contribution or a return of capital from/to CONSOL Energy. No interest has been charged or paid to CNX Gas under the aforementioned arrangement with CONSOL Energy.

Cash and cash equivalents include cash on hand and in banks 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, such as customer bankruptcies. CNX Gas regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

Property, Plant and Equipment

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

Upon the sale or retirement of a complete or partial unit of proved property, the cost and related accumulated depletion are eliminated from the property accounts, and the resultant gain or loss is recognized in operating 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, mineral interests, wells and related equipment and intangible drilling costs on a units of production method using the ratio of current production to the estimated aggregate proved developed gas reserves. Units-of-production amortization rates are revised whenever there is an indication of the need for revision, but at least once a year and accounted for prospectively.

Impairment of Long-Lived Assets

Impairment of long-lived assets, including investment in affiliates, 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. No adjustments were necessary during the periods presented.

Income Taxes

CNX Gas is included in the consolidated federal income tax return of CONSOL Energy. Income taxes are calculated as if CNX Gas had filed a tax return on a separate company basis. Deferred tax assets and liabilities

69

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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

Pension Plan

As of December 31, 2005, CNX Gas participates in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The pension benefit obligation earned by salaried CNX Gas employees prior to the date of separation from CONSOL Energy, remains with CONSOL Energy. As of the date of separation, any incremental pension liability earned by CNX Gas salaried employees is the obligation of CNX Gas. The benefits for this plan are based primarily on years of service and employees’ compensation near retirement. Effective January 1, 2006, an amendment was made to the CONSOL Energy Retirement Plan that suspended all service accruals of gas employees in this plan. In its place, an identical plan was created sponsored by CNX Gas to provide a benefit for all service accruals going forward.

Postretirement Benefits Other Than Pensions

Postretirement benefits other than pensions are accounted for in accordance with Statement of Financial Accounting Standards (SFAS) No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions,” which requires employers to accrue the cost of such retirement benefits for the employees’ active service periods. Such liabilities are actuarially determined and recorded on a discounted basis.

Gas Well Plugging Costs

As of January 1, 2003, CNX Gas accrues for dismantling and removing costs of gas related facilities using the accounting treatment prescribed by Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This statement requires the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The present value of the estimated asset retirement costs is capitalized as part of the carrying amount of the long-lived asset. Depreciation of the capitalized asset retirement cost is generally determined on a units-of-production basis. Accretion of the asset retirement obligation is recognized over time and generally will escalate over the life of the producing asset, typically as production declines. Asset retirement obligations primarily relate to the plugging of gas wells upon exhaustion of the gas reserves. Under previously applied accounting standards, such obligations were recognized ratably over the life of the producing assets, primarily on a units-of-production basis.

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

Revenue Recognition

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

We have an operational balancing agreement with Columbia. This agreement is in accordance with the Council of Petroleum Accountants Societies’ definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical

70

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

deliveries. As the operator, CNX Gas is responsible for monitoring this imbalance and making adjustments to sales volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser. The financial impacts of these imbalances were an $899 increase to expense and a $266 reduction to expense as of the twelve months ended December 31, 2005 and 2004 respectively.

CNX Gas sells purchased 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 transfer fee. CNX Gas also provides gathering services to third parties by way of matching gas buy/sells. These revenues and expenses are recorded gross in the statement of operations and recognized immediately in earnings.

CNX Gas also provides gathering services to third parties by way of a per mcf fee.

Royalty Recognition

Royalty expenses for gas rights are included in cost of goods sold and other charges when the related revenue for the gas sale is recognized. These royalty expenses 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 recorded gross. 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, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties.

Derivative Instruments

CNX Gas accounts for derivative instruments in accordance with Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) and its corresponding amendments under SFAS No. 138. SFAS No. 133 requires CNX Gas to measure every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and record them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period.

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.

71

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

As of December 31, 2005, CNX Gas had five outstanding swap derivative instruments designated as cash flow hedges, of which all were considered to be highly effective.

Stock Based Compensation

CNX Gas has implemented the disclosure-only provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation (SFAS No. 123).” CNX Gas continues to measure compensation expense for our stock-based compensation plans using the intrinsic value based method of accounting prescribed by Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” as amended. Generally, no stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price equal to the market value of the underlying common stock on the date of the grant. CNX Gas will implement SFAS No. 123R on January 1, 2006, as required, and begin to include stock-based employee compensation cost in net income. The following table illustrates the effect on net income and earnings per share if CNX Gas had applied the fair value recognition provisions of SFAS No. 123, to stock-based employee compensation:

	For the Twelve Months Ended December 31, 2005
Net income, as reported	$	102,168
Add: Stock-based compensation expense for restricted stock units		205
Deduct: Total stock-based employee compensation expense determined under Black-Scholes option pricing model and stock-based compensation expense for restricted stock units		(423	)
Pro forma net income (loss)	$	101,950
Earnings per share:
Basic—as reported	$	0.76
Basic—pro forma	$	0.76
Diluted—as reported	$	0.76
Diluted—pro forma	$	0.76

The pro forma adjustments in the current period are not necessarily indicative of future period pro forma adjustments as the assumptions used to determine fair value can vary significantly and the number of future shares to be issued under these plans is unknown. See Note 13—Stock Based Compensation.

Earnings Per Share

On June 21, 2005, the Board of Directors of CONSOL Energy authorized the incorporation of CNX Gas. On June 30, 2005, CNX Gas was incorporated and issued 100 shares of its $0.01 par value common stock to Consolidation Coal Company, a wholly-owned subsidiary of CONSOL Energy. CNX Gas was incorporated to conduct CONSOL Energy’s gas exploration and production activities. In August 2005, CONSOL Energy contributed or leased substantially all of the assets of its gas business, including all of CONSOL Energy’s rights to CBM associated with 4.5 billion tons of coal reserves owned or controlled by CONSOL Energy as well as all of CONSOL Energy’s rights to conventional gas. In exchange for its contribution of assets, CONSOL Energy received approximately 122.9 million shares of CNX Gas common stock. CNX Gas entered into various agreements with CONSOL Energy that will define various operating and service relationships between the two companies.

72

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

In August 2005, CNX Gas entered into an agreement to sell approximately 24.3 million shares in a private transaction and granted a 30-day option to purchase an additional 3.6 million shares. In August 2005, CNX Gas closed on the sale of all 27.9 million shares. The shares were sold to qualified institutional, foreign and accredited investors in a private transaction exempt from registration under Rule 144A, Regulation S and Regulation D. The proceeds (approximately $420,167, which includes proceeds from the additional 3.6 million shares) were used to pay a special dividend to Consolidation Coal Company. In addition, CONSOL Energy paid approximately $6,000 in expenses related to this transaction. Later, in August 2005, a Registration Statement on Form S-1 was filed with the SEC with respect to those shares. The registration statement was declared effective on January 18, 2006.

Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the twelve months ended December 31, 2005, 2004 and 2003. However, because CNX Gas was formed as a subsidiary of CONSOL Energy, the number of shares issued following formation is utilized for the 2004 and 2003 periods presented. Diluted earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, if dilutive, and the assumed redemption of restricted stock units. The number of additional shares is calculated by assuming the outstanding stock options were exercised and the 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. There were no anti-dilutive shares for the periods presented.

	For the Twelve Months Ended December 31,
	2005		2004		2003
Net Income	$	102,168	$	80,788	$	51,714
Weighted Average Number of Common Shares Outstanding:
Basic		134,071,334		122,896,667		122,896,667
Effect of stock options		65,885		91,692		91,692
Diluted		134,137,219		122,988,359		122,988,359
Earnings per share:
Basic	$	0.76	$	0.66	$	0.42
Diluted	$	0.76	$	0.66	$	0.42

The computations for basic and diluted earnings per share from continuing operations before considering the cumulative effect of changes in accounting principles are as follows:

	For the Twelve Months Ended December 31,
	2005		2004		2003
Basic	$	0.76	$	0.66	$	0.40
Diluted	$	0.76	$	0.66	$	0.40

73

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

In addition, on our consolidated statements of income, CNX Gas has presented unaudited pro forma EPS as if the sale of shares occurred at the beginning of the period presented. Below is our computation of that unaudited pro forma EPS:

	For the Twelve Months Ended December 31, 2005
Net Income	$	102,168
Pro Forma
Weighted Average Number of Common Shares Outstanding:
Basic		150,833,334
Effect of stock options		65,885
Dilutive		150,899,219
Earnings per share:
Basic	$	0.68
Diluted	$	0.68

Recent Accounting Pronouncements

In September 2005, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for transactions that CNX Gas considers matching buy/sell transactions will be affected by this consensus and therefore, upon adoption, these transactions will no longer be recorded on a gross basis. CNX Gas is currently studying the provisions of this consensus to determine the impact on its consolidated financial statements; however, management does not believe any impact on net income would be material. There will be no impact on cash flows from operations as a result of adoption.

In June 2005, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 154, “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3”. This Statement provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. This Statement also provides guidance for determining whether retrospective application of a change in accounting principle is impracticable and for reporting a change when retrospective application is impracticable. The correction of an error in previously issued financial statements is not an accounting change. However, the reporting of an error correction involves adjustments to previously issued financial statements similar to those generally applicable to reporting an accounting change retrospectively. Therefore, the reporting of a correction of an error by restating previously issued financial statements is also addressed by this Statement. This Statement shall be effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. We do not expect this guidance to have a significant impact on CNX Gas.

74

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

In April 2005, the FASB issued FSP No. FAS 19-1 “Accounting for Suspended Well Costs” (FSP 19-1). This position concluded that exploratory well costs should continue to be capitalized beyond twelve months when the well has found a sufficient quantity of reserves to justify its completion as a producing well, and the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. This guidance requires management to exercise more judgment than was previously required and also requires additional disclosure. Management does not believe this statement of position will have a significant effect on the financial statements.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation (FIN) 47, “Accounting for Conditional Asset Retirement Obligations, an interpretation of FASB Statement No. 143”. This interpretation clarifies that the term, conditional asset retirement obligation, as used in FASB Statement No. 143, refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred, generally upon acquisition, construction, or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. SFAS No. 143 acknowledges that, in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. We do not expect this guidance to have a significant impact on CNX Gas.

On December 15, 2004, the FASB released its final revised standard entitled FASB Statement No. 123R, “Share-Based Payment” (SFAS No.123R). This Statement requires that all public entities measure the cost of equity-based service awards based on the grant-date fair value. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award or the requisite service period, which usually is the vesting period. Compensation cost is not recognized for equity instruments for which employees do not render the requisite service. In addition, the SEC Staff issued Staff Accounting Bulletin (SAB) 107 on SFAS No. 123R in March 2005. The SAB was issued to assist preparers by simplifying some of the implementation challenges of SFAS No. 123R while enhancing information that investors receive. This SAB provides guidance related to, among other relevant items, share-based payment transactions with non-employees, valuation methods, the classification of compensation expense, non-GAAP financial measures, first-time adoptions of SFAS No.123R in an interim period, capitalization of compensation cost related to share-based payment arrangements, the accounting for income tax effects, the modification of employee share options prior to adoption of SFAS No. 123R, and disclosures in Management’s Discussion and Analysis subsequent to adoption of SFAS No. 123R. SFAS No.123R is to be effective for public companies as of the beginning of the first annual reporting period that begins after June 15, 2005. CNX Gas will implement SFAS No. 123R on January 1, 2006, as required. The expected impact of unvested stock options outstanding at December 31, 2005, under the modified prospective application, is approximately a $1.4 million reduction in earnings before income taxes for the twelve months ended December 31, 2006. Management is currently evaluating the policy for determining our windfall tax benefits.

In October 2004, the FASB ratified Emerging Issues Task Force (EITF) Issue No. 04-10, “Applying Paragraph 19 of FASB Statement No. 131, ‘Disclosure about Segments of an Enterprise and Related Information,’ in Determining Whether to Aggregate Operating Segments That Do Not Meet the Quantitative Thresholds” (EITF 04-10). FASB Statement No. 131 requires that a public business enterprise report financial

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(Dollars in thousands)

and descriptive information about its reportable operating segments. Operating segments are components of an enterprise about which separate financial information is available that is evaluated regularly by the chief operating decision maker in deciding how to allocate resources and in assessing performance. EITF 04-10 clarifies how an enterprise should evaluate the aggregation criteria in paragraph 17 of FAS No. 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of FAS No. 131. In addition, the FASB Task Force has requested that the FASB staff propose a FASB Staff Position (FSP) to provide guidance in determining whether two or more operating segments have similar economic characteristics. The Task Force has agreed that since the two issues are interrelated, the effective date of EITF 04-10 should coincide with the future undetermined effective date of the anticipated FSP. We are currently evaluating the positions addressed in EITF 04-10, and foresee no significant changes in the reporting practices currently used to report segment information.

In October 2004, the American Jobs Creation Act of 2004 was signed into law. CNX Gas has implemented the qualified production activities deduction as enacted by the American Jobs Creation Act of 2004. The deduction is currently equal to 3% of qualified production activities income as limited by taxable income and as limited by 50 percent of the employer’s W-2 wages for the tax year. The percentage used in computing the deduction will be 3% in 2006, 6% in 2007 through 2009 and 9% in 2010 and after. As a special deduction in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” it is included as a permanent benefit in our estimate of our annual effective tax rate.

Reclassifications:

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2005 with no effect on previously reported net income or stockholders’ equity. The reclassifications include separately reporting the current portion of derivatives.

Note 2—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 also sells gas to Buchanan Generation, LLC, in which CNX Gas has a 50% interest, on both a market and discounted basis, depending upon the circumstances. CNX Gas also purchases various supplies from CONSOL Energy’s wholly owned subsidiary Fairmont Supply; the cost of these items reflect current market prices and are included in cost of goods sold as arms-length transactions. The following table reflects the amounts of these transactions:

	For the Twelve Months Ended December 31,
	2005		2004		2003
Sales of Gas-Related Party	$	6,052	$	22,036	$	32,572
Supply Purchases	$	135	$	137	$	89

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:

Cash management for CNX Gas is conducted by CONSOL Energy. In October of 2005, CNX Gas established a $200 million credit facility with a consortium of banking institutions and no longer uses the previous CONSOL Energy arrangement to obtain working capital funds.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

General and administrative expenses contain fees of $5,669, $6,327 and $3,194 for the twelve months ended December 31, 2005, 2004 and 2003, respectively, for certain accounting and administrative services provided by CONSOL Energy. These fees are allocated to CNX Gas based on annual estimated hours worked on CNX Gas and related companies versus total hours available.

CNX Gas paid CONSOL Energy $12,121 for federal and state taxes due related to income for the twelve months ended December 31, 2005. CNX Gas also paid CONSOL Energy $9,278 for services rendered from the date of separation through December 31, 2005, in accordance with the Services Agreement.

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. We estimate that the historical cost to CONSOL Energy of drilling these wells was as follows: $6,200 in 2005, $9,100 in 2004, and $9,300 in 2003. CNX Gas captures and markets the gas from these wells and, therefore, benefits from this drilling activity, although we are 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 reflected in CNX Gas’ historical financial statements. Our master cooperation and safety agreement with CONSOL Energy retains this cost structure after our separation from CONSOL Energy.

As of December 31, 2005, CNX Gas participates in a non-contributory defined benefit retirement plan, administered by CONSOL Energy, covering substantially all salaried employees. The pension benefit obligation earned by salaried CNX Gas employees prior to the date of separation from CONSOL Energy, remains with CONSOL Energy. CNX Gas’ allocation of the pension expense under this plan was $526 up to the point of separation in 2005, and $1,433 and $1,035 for the twelve months ended December 31, 2004 and 2003, respectively. CONSOL Energy’s allocation of the expense for this plan was based on the percentage of CNX Gas’ active employee salary wages compared to the total active employee salary wages covered by the plan. As of the date of separation, any incremental pension liability earned by CNX Gas salaried employees is the obligation of CNX Gas. The benefits for this plan are based primarily on years of service and employees’ compensation near retirement. Effective January 1, 2006, an amendment was made to the CONSOL Energy Retirement Plan that suspended all service accruals of gas employees in this plan. In its place, an identical plan was created sponsored by CNX Gas to provide a benefit for all service accruals going forward. As of this date, the lump sum benefits formula has been frozen for service and salaries and prospectively the lump sum option will not be offered for any benefits earned after January 1, 2006. Also the amount of future benefit accruals have been reduced and early retirement subsidies have been eliminated.

Employees may also elect to participate in a defined contribution investment plan administered by CONSOL Energy. Amounts charged to expense by CNX Gas for the investment plan were $442, $337 and $294 for the twelve months ended December 31, 2005, 2004 and 2003, respectively. CONSOL Energy charges CNX Gas the actual amounts contributed by CONSOL Energy on behalf of CNX Gas’ employees.

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 $228, $140 and $152 for the twelve months ended December 31, 2005, 2004 and 2003, 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 is insured for workers’ compensation claims in several states in which we operate and is self-insured for these claims in West Virginia and Virginia. Workers’ compensation expense for these benefits was

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

$34, $22 and $11 for the twelve months ended December 31, 2005, 2004 and 2003, respectively. These expenses are allocated based upon active employees of CNX Gas compared to total employees covered by the plan.

CONSOL Energy has provided financial guarantees on behalf of CNX Gas. At December 31, 2005, these financial guarantees are as follows:

• CNX Gas has an agreement with CONOCO/Phillips, Inc. that guarantees the physical delivery of CNX Gas production through December 31, 2005. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas to this sales agreement, up to $60,000.

• CONSOL Energy has an agreement with Dominion Field Services to guarantee any unpaid obligations of CNX Gas and Greene Energy, pursuant to their gas sales agreements with Dominion Field Services. The maximum undiscounted future payments required pursuant to the agreement are as follows: (a) CNX Gas—$36,000, and (b) Greene Energy—$3,000.

• CONSOL Energy has an agreement with AEP Energy Services to unconditionally guarantee the full and prompt payment of all obligations, up to $30,000 of CNX Gas, arising from AEP Energy Services’ purchase, sale or exchange of energy services or energy related commodities with respect to the sales agreement between CNX Gas and AEP Energy Services.

• CONSOL Energy entered into an International Swap and Derivative Association (ISDA) Agreement with Morgan Stanley Capital Group in December 2003. This agreement covers the gas derivative hedging activity of CNX Gas.

• CONSOL Energy is the guarantor of the agreement dated May 26, 2004 between CNX Gas and Equitable Energy, LLC, relating to the purchases and/or trades of natural gas and/or natural gas products, electric energy or capacity, financial derivatives or related contracts. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas related to this agreement, up to $10,000. The guaranty shall be a continuing guaranty and CONSOL Energy has the right to terminate the guaranty by providing Equitable Energy, LLC 30 day’s written notice.

• CONSOL Energy has an International Swap and Derivative Association (ISDA) Agreement with Citibank effective November 21, 2002. This agreement covers the gas derivative hedging activity of CNX Gas.

• CNX Gas has an agreement dated December 31, 2004 with Baltimore Gas and Electric Company that guarantees the prompt and complete payment of all obligations and amounts owed to BGE related to the purchase and/or sale of natural gas. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas related to this agreement, up to $3,000. The guarantee will continue in force until 30 days prior written notice is given from CONSOL Energy to Baltimore Gas and Electric Company.

• CONSOL Energy is the guarantor of the agreement dated October 22, 2004 between CNX Gas and East Tennessee Natural Gas LLC, relating to the sale, purchase, exchange, storage or transportation of natural gas. CONSOL Energy has guaranteed any unpaid obligation of CNX Gas related to this agreement, limited to $100 in the aggregate, plus reasonable costs and expenses incurred by East Tennessee Natural Gas LLC, in collecting the obligation and/or enforcing this guarantee. In the event that CNX Gas defaults in the payment of any of the obligations, within 30 days after receiving written notice from East Tennessee Natural Gas LLC, CONSOL Energy shall make such payment or otherwise cause the same to be paid.

• CONSOL Energy is the guarantor of the agreement between CNX Gas and Columbia Gas Transmission Corporation dated April 14, 2004, related to all natural gas transportation and services agreed to between us and Columbia Gas Transmission Corporation.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

• CONSOL Energy is the guarantor of the agreement between CNX Gas and TXU Portfolio Management Company dated March 9, 2005 that guarantees the payment of all obligations of CNX Gas Company up to $5,000.

• CONSOL Energy has an agreement dated October 29, 2004 with Sequent Energy Management to guarantee the obligations of CNX Gas relating to the purchase, sale or exchange of natural gas or other hydrocarbons or non-combustible gases.

• CONSOL Energy guaranteed the obligations of CNX Gas up to a maximum amount of approximately $53,000 under the agreements entered into between CNX Gas and East Tennessee related to the Jewell Ridge lateral gas pipeline.

The financial statements of CNX Gas, for the twelve months ended December 31, 2004 and 2003 were prepared to reflect the impact of these contractual arrangements with CONSOL Energy. As a result, management believes the financial statements present, in all material respects, the results of operations and financial position of CNX Gas as if it were operating as an autonomous entity.

Note 3—Other Income:

	For the Twelve Months Ended December 31,
	2005		2004		2003
Other Royalty Income	$	8,158	$	5,726	$	3,968
Third Party Gathering Revenue		1,110		1,109		440
Sales of Oil Production		54		54		61
Interest Income		418		—		—
Miscellaneous		119		27		16
Total Other Income	$	9,859	$	6,916	$	4,485

Note 4—Income Taxes:

Income taxes provided on earnings consisted of:

	For the Twelve Months Ended December 31,
	2005		2004		2003
Current:
Federal	$	14,713	$	941	$	—
State		3,058		—		—
Deferred:
Federal		38,957		42,250		27,799
State		7,822		8,707		3,403
Total Income Tax Expense	$	64,550	$	51,898	$	31,202

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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

	December 31,
	2005			2004
Deferred Tax Assets:
Derivatives	$	22,266		$	3,638
Well Plugging		4,285			3,411
Other post employment benefits		1,321			1,219
Federal Net Operating Loss		—			3,326
State Net Operating Loss		—			407
Minimum Tax Credit		—			941
Other Assets		—			(11	)
Total Deferred Tax Assets		27,872			12,931
Deferred Tax Liabilities:
Property, Plant and Equipment		(58,588	)		(180,573	)
Investment in Equity Affiliates		(7,681	)		(7,681	)
Total Deferred Tax Liabilities		(66,269	)		(188,254	)
Net Deferred Tax Liabilities	$	(38,397	)	$	(175,323	)

CNX Gas files its federal tax return and some of its state tax returns as a member of the CONSOL Energy consolidated group. Income taxes are calculated as if CNX Gas had filed a tax return on a separate company basis. Deferred tax assets and liabilities are recognized for the expected future tax consequences of events that have been recognized in CNX Gas’ financial statements or separate tax return that would be filed on a separate company basis.

CNX Gas has implemented the qualified production activities deduction as enacted by the American Jobs Creation Act of 2004. The deduction is currently equal to 3% of qualified production activities income as limited by taxable income and as limited by 50 percent of the employer’s W-2 wages for the tax year. CNX Gas has estimated the deduction to be $1,300 for 2005. As a special deduction in accordance with FASB Statement No. 109, “Accounting for Income Taxes,” it is included as a permanent benefit in CNX Gas’ estimate of its annual effective tax rate.

For the twelve months ended December 31, 2005, CNX Gas fully utilized $9,503 of net operating loss that was carried forward from the previous year.

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:

	Twelve Months Ended December 31,
	2005					2004					2003
	Dollars			Rate		Dollars			Rate		Dollars			Rate
Statutory U.S. Federal Income Tax Rate	$	58,351		35.0	%	$	46,440		35.0	%	$	28,004		35.0	%
Net Effect of State Income Tax		7,072		4.2	%		5,659		4.3	%		3,403		4.3	%
Effect of tax depletion in excess of tax basis		(426	)	(0.3	)%		(210	)	(0.2	)%		(208	)	(0.3	)%
Other		(447	)	(0.2	)%		9		—			3		—
Income Tax Expense/ Effective Rate	$	64,550		38.7	%	$	51,898		39.1	%	$	31,202		39.0	%

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 5—Changes in Accounting for Gas Well Plugging Costs:

Effective January 1, 2003, CNX Gas adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). As a result of this statement, CNX Gas recognized a reduction of liabilities of $2,699 for asset retirement obligations associated with the costs of gas well plugging. In addition, CNX Gas capitalized asset retirement costs by increasing the carrying amount of related long-lived assets, net of the associated accumulated depreciation, by $2,085.

The cumulative effect adjustment recognized in 2003 upon the adoption of this statement was a gain of $2,905 net of deferred taxes of approximately $1,879.

The reconciliation of changes in the asset retirement obligations at December 31, 2005 and 2004 is as follows:

	As of December 31,
	2005			2004
Balance at beginning of period	$	8,685		$	7,422
Accretion expense		660			525
Payments		(1,086	)		(394	)
Revisions in estimated cash flows		2,752			1,132
Other		(103	)		—
Balance at end of period	$	10,908		$	8,685

Note 6—Sales of Trade Accounts Receivable:

In April 2003, CNX Gas entered into an agreement with CNX Funding Corporation, a wholly owned special purpose, bankruptcy-remote subsidiary of CONSOL Energy. Under these agreements with CNX Funding Corporation, CNX Gas, irrevocably and without recourse, sold the majority of our trade accounts receivable to CNX Funding on a monthly basis. For the twelve months ended December 31, 2004, $284,340 of CNX Gas’ receivables were sold to CNX Funding. At December 31, 2004, $28,158 was removed from CNX Gas’ trade receivable balance. This transaction resulted in a discount of $1,964 in the twelve months ended December 31, 2004. CNX Gas discontinued this arrangement as of the date of separation and therefore no receivables were sold at December 31, 2005 or prior to that time following discontinuance of CNX Gas’ participation in the receivables facility.

Note 7—Other Current Assets:

	As of December 31,
	2005		2004
Gas Firm Transportation	$	15,689	$	4,431
Land Option Deposit		798		1,200
Other		1,580		954
Total Other Current Assets	$	18,067	$	6,585

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 8—Property, Plant and Equipment:

	As of December 31,
	2005			2004
Surface Lands	$	26,573		$	18,240
Mineral Interests		55,621			55,620
Wells and Related Equipment		141,959			111,205
Intangible Drilling		312,467			263,403
Gathering Assets		344,355			319,680
Gas Well Plugging		7,680			3,217
Other		36			74
Total Property, Plant and Equipment		888,691			771,439
Accumulated Depreciation		(165,144	)		(130,563	)
Property and Equipment, net	$	723,547		$	640,876

Note 9—Credit Facility:

CNX Gas entered into a credit agreement for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. The $200,000 credit agreement for CNX Gas is unsecured, however it does contain a negative pledge provision providing that CNX Gas assets cannot be used to secure any other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CNX Gas stock and merge with another corporation. The facility includes a leverage ratio covenant of not more than 3.0 to 1.0, measured quarterly. As there was no debt outstanding at December 31, 2005, the leverage ratio was 0.0 to 1.0 at December 31, 2005. The facility also includes an interest coverage ratio of no less than 3.0 to 1.0 measured quarterly. As such, interest expense was immaterial. Therefore the interest coverage ratio covenant was met.

At December 31, 2005, the CNX Gas credit agreement had no borrowings outstanding and $14,436 of letters of credit outstanding, leaving $185,564 of capacity available for borrowings and the issuance of letters of credit.

As a result of entering into the $200,000 credit agreement, CNX Gas and subsidiaries have executed a Supplemental Indenture and are guarantors of CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture and the agreement governing CONSOL Energy’s 8.25% medium term notes due 2007 in the principal amount of $45,000 would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes. CONSOL Energy has advised us that, in accordance with its previously stated intention, CONSOL Energy sought to obtain an amendment to its indenture for the 7.875% notes in order to obtain the release of CNX Gas and its subsidiaries as guarantors of the 7.875% notes. Based on its discussions with a number of the note holders, CONSOL Energy has determined that, at this time, it cannot obtain an amendment of the indenture on commercially acceptable terms. Therefore, CONSOL Energy will not formally solicit the 7.875% note holders for the release and, consequently, we will remain guarantors of the 7.875% notes.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 10—Other Current Liabilities:

	As of December 31,
	2005		2004
Gas Firm Transportation	$	15,945	$	4,780
Short Term Incentive Compensation Plan		2,755		—
Other		2,371		1,332
Total Other Current Liabilities	$	21,071	$	6,112

Note 11—Leases:

CNX Gas uses various leased facilities and equipment in our operations. All such leased facilities and equipment qualify as operating leases. Future minimum lease payments under these operating leases are as follows:

	Annual Operating Leases
2006	$	372
2007		251
2008		129
2009		128
2010		129
Thereafter		905
Total minimum lease payments	$	1,914

Rental expense under operating leases was $2,892, $1,566 and $2,563 for the twelve months ended December 31, 2005, 2004 and 2003, respectively.

Note 12—Pension and Other Postemployment Benefits:

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

CNX Gas participates in certain CONSOL Energy sponsored benefit plans which provides 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

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include a cost sharing structure 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 does not expect to contribute to the other postemployment benefit plan in 2006. CNX Gas expects to pay benefit claims as they become due.

CNX Gas uses a September 30 measurement date for its other postemployment benefit plans.

The reconciliation of changes in the benefit obligation and funded status of these plans at December 31, 2005 and 2004 is as follows:

	At December 31,
	Pension			Other Benefits
	2005			2005			2004
Change in benefit obligation:
Benefit obligation at beginning of period	$	—		$	2,826		$	2,996
Service costs		219			160			131
Interest costs		—			170			163
Actuarial gain		(131	)		(765	)		(464	)
Plan amendments		—			(631	)		—
Benefit obligation at end of period	$	88		$	1,760		$	2,826
Funded Status:
Under funded obligation	$	(88	)	$	(1,760	)	$	(2,826	)
Unrecognized prior service credit		—			(1,631	)		(1,112	)
Unrecognized net actuarial (loss)/gain		(131	)		23			829
Accrued benefit costs	$	(219	)	$	(3,368	)	$	(3,109	)
Amounts recognized in the Consolidated Balance Sheet consist of:
Prepaid Benefit Cost	$	—		$	(3,109	)	$	—
Accrued Benefit Liability		(219	)		(259	)		(3,109	)
Accumulated Other Comprehensive Loss		—			—			—
Intangible Asset		—			—			—
Accrued benefit costs	$	(219	)	$	(3,368	)	$	(3,109	)

The accumulated benefit obligation for the CNX Gas portion of the Employee Retirement Plan administered by CONSOL Energy at December 31, 2005 was $74.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

The components of net periodic benefit costs are as follows:

	For the Twelve Months Ended December 31,
	Pension		Other Benefits
	2005		2005			2004			2003
Components of Net Periodic Benefit Costs:
Service costs	$	207	$	160		$	131		$	203
Interest costs		12		170			163			261
Amortization of prior service costs credit		—		(113	)		(117	)		(80	)
Recognized net actuarial loss		—		42			63			95
Benefit costs	$	219	$	259		$	240		$	479

CNX Gas has recognized the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) in the year ended December 31, 2004 in accordance with the FASB Staff Position No. 106-2, “Accounting and Disclosure Requirements related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.” Implementation of the Act resulted in a reduction of other postemployment benefit costs of $52 for the period March 8, 2004 through December 31, 2004, and a reduction of $335 to our December 31, 2004 estimated other postemployment benefit obligation. These effects are included in the actuarial (gain) loss line in the tables above.

Assumptions:

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

	Pension Benefits at December 31, 2005		Other Benefits at December 31,
			2005		2004		2003
Discount rate	5.75	%	5.75	%	6.00	%	6.75	%
Expected long-term return on plan assets	8.00	%	8.00	%	8.00	%	8.00	%
Rate of compensation increase	4.11	%	—		—		—

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

	Pension Benefits at December 31, 2005		Other Benefits at December 31,
			2005		2004		2003
Discount rate	6.00	%	6.00	%	6.00	%	6.75	%
Expected long-term return on plan assets	8.00	%	8.00	%	8.00	%	8.00	%
Rate of compensation increase	4.12	%	—		—		—

CNX Gas has no plan assets as of December 31, 2005 for either pension or other postemployment benefits.

The assumed health care cost trend rates are as follows:

	December 31,
	2005		2004		2003
Health care cost trend rate for next year	9.25	%	10.00	%	10.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)	4.75	%	4.75	%	4.75	%
Year that the rate reaches ultimate trend rate	2011		2011		2010

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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	$	44	$	(33	)
Effect on accumulated postemployment benefit obligation		210		(283	)

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

	0.25-Percentage Point Increase			0.25-Percentage Point Decrease
Effect on total of service and interest costs components	$	(4	)	$	4
Effect on accumulated postemployment benefit obligation		(2	)		1

Cash Flows:

CNX Gas intends to pay other postemployment benefit claims as they are due. The following benefit payments reflecting future service are expected to be paid as follows:

	Pension Payments		Other Benefits Payments
2006	$	1	$	5
2007		2		16
2008		6		29
2009		10		43
2010		25		61
Year 2011-2015		251		668

Note 13—Stock-Based Compensation:

CNX Gas adopted the CNX Gas Equity Incentive Plan on June 30, 2005, and amended the plan on August 1, 2005. The amended plan was approved by the sole stockholder of CNX Gas, CONSOL Energy, on August 4, 2005. The plan is administered by our board of directors and the board of directors may delegate administration of the plan to a committee of the board of directors. Our directors, employees and consultants and our affiliates’ (which include CONSOL Energy) directors, employees and consultants are eligible to receive awards under the plan. Some of our employees including our executive officers and non-employee directors have participated in or have been eligible to participate in and, will continue to be eligible to participate in, CNX Gas’ equity incentive plan.

The CNX Gas equity incentive plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, and other stock-based awards. 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. As of December, 31, 2005 our board has granted 92,969 shares of common stock underlying restricted stock units and 1,041,026 shares of common stock underlying stock options to officers, directors and employees of CNX Gas.

CNX Gas accounts for stock options granted to employees and non-employee directors in accordance with APB 25.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

The fair value of each option granted is estimated on the day of the grant using the Black-Scholes option-pricing model in accordance with SFAS No. 123. The weighted average assumptions used were:

	December 31, 2005
Expected dividend yield	0.00	%
Expected volatility	36.54	%
Risk-free interest rate	4.28	%
Expected life	4.5 years

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

	Shares		Weighted Average Exercise Price
Balance at December 31, 2004	—			—
Granted	1,041,026		$	16.05
Exercised	—			—
Forfeited	(450	)		16.00
Balance at December 31, 2005	1,040,576		$	16.05

At December 31, 2005 there were no exercisable options.

All stock options granted in 2005 had exercise prices equal to their fair market value at the date of grant. For options granted prior to September 12, 2005, the exercise price was based upon the price of CNX Gas stock pursuant to the private placement at the time the options were granted. Trading in the PORTAL market began on September 12, 2005. Options granted after this date had an exercise price equal to the market value reflected in this PORTAL market at the time of grant. The weighted average per share fair value of options as of the grant date was $5.34 at December 31, 2005. The weighted average remaining life of the outstanding options at December 31, 2005 is 9.6 years.

No compensation expense is recognized because the exercise price of the stock options equals the estimated market price of the underlying stock at the date of the grant and the number of shares issued is fixed. These stock options will terminate ten years after the date on which they were granted. The employee stock options, covered by the Equity Incentive Plan adopted June 30, 2005 vest 25% per year, beginning one year after the grant date. There are 1,040,576 stock options outstanding under this plan. Non-employee director stock options vest 33% per year. There are no non-employee director stock options outstanding at December 31, 2005. The vesting of the options will accelerate in the event of death, disability or retirement and may accelerate upon a change of control of CNX Gas.

Restricted Stock Unit Awards are grants that entitle the holder to receive shares of common stock as the award vests. A total of 92,969 restricted stock units were outstanding at December 31, 2005, vesting over a remaining weighted average period of 2.7 years. Each restricted stock unit represents one share of common stock. The weighted average grant-date fair value of restricted stock units granted in the twelve months ended December 31, 2005 was $16.00 (based upon the estimated market value of CNX Gas stock at the time of grant). Compensation expense will be recognized over the vesting period of the units.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 14—Other Comprehensive Loss:

Accumulated other comprehensive loss consists entirely of the following:

	Change in Fair Value of Cash Flow Hedges
Balance at December 31, 2002	$	(1,823	)
Current period change		(3,573	)
Balance at December 31, 2003		(5,396	)
Current period change		(227	)
Balance at December 31, 2004		(5,623	)
Current period change		(29,110	)
Balance at December 31, 2005	$	(34,733	)

The cash flow hedges that CNX Gas holds are disclosed in Note 17.

Note 15—Supplemental Cash Flow Information:

	For the Twelve Months Ended December 31,
	2005			2004			2003
Cash paid during the year for:
Interest	$	14		$	—		$	—
Income Taxes	$	12,233			—			—
Non-cash investing and financing activities:
Tax basis step-up	$	(165,041	)		—			—
Assumed ownership of joint venture assets	$	(4,769	)		—			—
Accounting for gas well plugging costs (Note 5)
Change in assets	$	(3,591	)	$	(500	)	$	(6,450	)
Change in liabilities	$	(3,591	)	$	(500	)	$	(6,450	)

Note 16—Concentration of Credit Risk:

CNX Gas markets methane gas for sale primarily to gas wholesalers. Credit is extended based on an evaluation of the customer’s financial condition, and generally collateral is not required. Credit losses consistently have been minimal.

During the twelve months ended December 31, 2005, 2004 and 2003, CNX Gas made sales to certain unrelated entities which individually comprised greater than 10% of total revenues. The following is a table summarizing the percentage of revenue provided by each customer.

	For the Twelve Months Ended December 31,
	2005		2004		2003
Dominion	29	%	22	%	8	%
Conoco	19	%	13	%	51	%
Columbia Gas	10	%	—		—
American Electric Power	8	%	17	%	24	%
Allegheny Energy	—		—		14	%

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 17—Derivative Instruments:

CNX Gas has entered into derivative financial instruments, for purposes other than trading, to convert the market prices related to these anticipated sales of natural gas to fixed prices. These instruments are designated as cash flow hedges and extend through 2008. The net fair values of the outstanding instruments are liabilities of $56,686 and $9,261 at December 31, 2005 and 2004, respectively.

CNX Gas entered into cash flow hedges for natural gas in 2005, 2004 and 2003. Gains or losses related to these derivative instruments were recognized when the sale of the natural gas affected earnings. The ineffective portion of the changes in the fair value of these contracts was insignificant in 2005. There was no ineffectiveness in 2004 related to this hedging strategy.

For these cash flow hedge strategies, the fair values of the derivatives are recorded on the balance sheet. The effective portions of the changes in fair values of the derivatives are recorded in accumulated other comprehensive income and loss and are reclassified to sales in the period in which earnings are impacted by the hedged items or in the period that the transaction no longer qualifies as a cash flow hedge. There were no transactions that ceased to qualify as a cash flow hedge in 2005 or 2004, CNX Gas’ consolidated balance sheet is reflected on a net asset/(liability) basis for each counterparty.

Assuming market prices remain constant with prices at December 31, 2005, $14,437 of the $34,733 loss included in other comprehensive income is expected to be recognized in earnings over the next 12 months.

CNX Gas did not have any derivatives designated as fair value hedges in 2005, 2004 and 2003.

Note 18—Commitments and Contingent Liabilities:

CNX Gas has various purchase commitments for materials, supplies and items of permanent investment incidental to the ordinary conduct of business. Such commitments are not at prices in excess of current market value.

CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2001. For these years, CNX Gas has filed appropriate returns and has paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County as of December 31, 2005. Additionally, on April 29, 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a “Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code §8.01-184” against us in the Circuit Court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002. The complaint alleges that we failed to properly calculate the amount of license taxes we owed to Buchanan County related to our production and sale of CBM gas in Buchanan County. Buchanan County is seeking a determination by the court that we have calculated, and continue to calculate, the license tax in an improper manner. We have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability on our balance sheet in an amount based on the difference between our calculation of the tax and Buchanan County’s calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

CDX Gas, LLC has alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX has demanded that we enter into a business arrangement with CDX to use its

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

patented technology. Alternatively, CDX has informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly covered by their patents. While CDX has not formally identified the wells where we used the allegedly infringing technology, we believe that 23 of our producing wells to date could be covered by their claim. CDX has also suggested that we breached a confidentiality agreement that one of our affiliates entered into with them in 2001. We deny all of these allegations and intend to vigorously contest them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania, seeking a judicial determination to the effect that the CDX patents are invalid and unenforceable and that we do not infringe any valid and enforceable claim of the CDX patents. CDX has filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain of their patents. This litigation is in a very early stage and we cannot predict the outcome.

In 1999, CNX Gas was named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty owners and to a class of plaintiffs who have yet to be determined. The claim of underpayment of royalties related to the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post production expenses of gathering compression and transportation. CNX Gas was ordered to, and subsequently in 2002 paid, approximately $7,000 to the group of royalty owners that brought the suit. An estimate of the payment was appropriately accrued in other cost of goods sold in previous periods. A final payment was made to the plaintiffs in 2003 for approximately $6,000 to adjust all royalties owed to the plaintiffs from the date of the court ruling forward, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of the aforementioned suit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various royalty owners using the court determined deductions from the settled case. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

In addition to the foregoing, CNX Gas is subject to various pending and threatened lawsuits and claims arising in the ordinary course of its business. While the relief claimed in these matters may be significant, we are unable to predict with certainty the ultimate outcome of such lawsuits and claims. We have established reserves for pending litigation which we believe are adequate, and after consultation with counsel and giving appropriate consideration to available insurance, we believe that the ultimate outcome of any matter currently pending against CNX Gas will not materially affect the financial position of CNX Gas.

CONSOL Energy has provided financial guarantees to certain third parties on our behalf. These financial guarantees are as follows:

• CNX Gas has an agreement with CONOCO/Phillips, Inc. that guarantees the physical delivery of CNX Gas production through December 31, 2005. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas to this sales agreement, up to $60,000.

• CONSOL Energy has an agreement with Dominion Field Services to guarantee any unpaid obligations of CNX Gas and Greene Energy, pursuant to their gas sales agreements with Dominion Field Services. The maximum undiscounted future payments required pursuant to the agreement are as follows: (a) CNX Gas—$36,000, and (b) Greene Energy—$3,000.

• CONSOL Energy has an agreement with AEP Energy Services to unconditionally guarantee the full and prompt payment of all obligations, up to $30,000 of CNX Gas, arising from AEP Energy Services’ purchase, sale or exchange of energy services or energy related commodities with respect to the sales agreement between CNX Gas and AEP Energy Services.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

• CONSOL Energy entered into an International Swap and Derivative Association (ISDA) Agreement with Morgan Stanley Capital Group in December 2003. This agreement covers the gas derivative hedging activity of CNX Gas.

• CONSOL Energy is the guarantor of the agreement dated May 26, 2004 between CNX Gas and Equitable Energy, LLC, relating to the purchases and/or trades of natural gas and/or natural gas products, electric energy or capacity, financial derivatives or related contracts. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas related to this agreement, up to $10,000. The guaranty shall be a continuing guaranty and CONSOL Energy has the right to terminate the guaranty by providing Equitable Energy, LLC 30 day’s written notice.

• CONSOL Energy has an International Swap and Derivative Association (ISDA) Agreement with Citibank effective November 21, 2002. This agreement covers the gas derivative hedging activity of CNX Gas.

• CNX Gas has an agreement dated December 31, 2004 with Baltimore Gas and Electric Company that guarantees the prompt and complete payment of all obligations and amounts owed to BGE related to the purchase and/or sale of natural gas. CONSOL Energy has guaranteed any unpaid obligations of CNX Gas related to this agreement, up to $3,000. The guarantee will continue in force until 30 days prior written notice is given from CONSOL Energy to Baltimore Gas and Electric Company.

• CONSOL Energy is the guarantor of the agreement dated October 22, 2004 between CNX Gas and ETNG, relating to the sale, purchase, exchange, storage or transportation of natural gas. CONSOL Energy has guaranteed any unpaid obligation of CNX Gas related to this agreement, limited to $100 in the aggregate, plus reasonable costs and expenses incurred by East Tennessee Natural Gas LLC, in collecting the obligation and/or enforcing this guarantee. In the event that CNX Gas defaults in the payment of any of the obligations, within 30 days after receiving written notice from East Tennessee Natural Gas LLC, CONSOL Energy shall make such payment or otherwise cause the same to be paid.

• CONSOL Energy is the guarantor of the agreement between CNX Gas and Columbia Gas Transmission Corporation dated April 14, 2004, related to all natural gas transportation and services agreed to between us and Columbia Gas Transmission Corporation.

• CONSOL Energy is the guarantor of the agreement between CNX Gas and TXU Portfolio Management Company dated March 9, 2005 that guarantees the payment of all obligations of CNX Gas Company up to $5,000.

• CONSOL Energy has an agreement dated October 29, 2004 with Sequent Energy Management to guarantee the obligations of CNX Gas relating to the purchase, sale or exchange of natural gas or other hydrocarbons or non-combustible gases.

• CONSOL Energy guaranteed the obligations of CNX Gas up to a maximum amount of approximately $53,000 under the agreements entered into between CNX Gas and East Tennessee related to the Jewell Ridge Lateral gas pipeline.

With respect to the above guarantees, we believe that once CNX Gas publishes its own financial statements in conformity with SEC rules, the counterparties to those guarantees will agree to release CONSOL Energy from its performance obligations, and CNX Gas will then become the guarantor of those obligations. Furthermore, we do not believe this shift in guarantees will result in a material increase in cost to us.

CNX Gas has provided financial guarantees and letters of credit to certain third parties as follows:

CNX Gas Corporation is the guarantor of an agreement with Washington Gas Light Company dated November 2, 2005 that guarantees all obligations related to gas and or electric purchase or sales agreements. Our liability is limited to an aggregate amount of $1,100.

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CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

On May 4, 2005, CNX Gas amended the amount of the existing letter of credit to Columbia Gas Transmission Corporation. The current amount issued as a letter of credit is $1,000. This letter of credit is to serve as collateral for all natural gas transportation and services as agreed to by the parties. This letter of credit will be called upon should CNX Gas fail to perform its obligation.

CNX Gas obtained the issuance of a letter of credit to East Tennessee Natural Gas, LLC to serve as collateral for a fifteen year firm transportation contract for 210,000 MMBTU per day on the Jewell Ridge Pipeline with a targeted in-service date of summer 2006. The amount of the letter of credit at December 31, 2005 is $13,284.

On April 15, 2005, CNX Gas obtained the issuance of a letter of credit to Allegheny Energy Supply Co. to serve as collateral for a period of one year to cover a potential tax liability of $152.

CNX Gas has issued miscellaneous surety bonds, primarily gas well plugging bonds, totaling $654. CNX Gas guarantees the performance of these obligations.

Note 19—Segment Information:

The principal activity of CNX Gas is to produce pipeline quality methane gas for sale primarily to gas wholesalers. CNX Gas has three reportable operating segments: Central Appalachia and Tennessee, Northern Appalachia and Gathering. These operating segments reflect the way CNX Gas manages our operations and makes business decisions.

Industry segment results for the twelve months ended December 31, 2005 are:

	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	302,095	$	20,287	$	—	$	322,382	$	—		$	322,382
Sales—related parties		5,969		83		—		6,052		—			6,052
Sales—purchased gas		275,148		—		—		275,148		—			275,148
Other revenue		8,695		54		1,110		9,859		—			9,859
Intersegment revenues		—		—		47,475		47,475		(47,475	)		—
Total Revenue and Other Income	$	591,907	$	20,424	$	48,585	$	660,916	$	(47,475	)	$	613,441
Earnings (Loss) Before Income Taxes	$	149,844	$	4,446	$	12,428	$	166,718	$	—		$	166,718	(A)
Segment assets	$	526,532	$	38,337	$	309,987	$	874,856	$	(20,073	)	$	854,783	(B)
Depreciation, depletion and amortization	$	20,109	$	3,421	$	11,509	$	35,039	$	—		$	35,039
Capital expenditures	$	87,652	$	21,870	$	1,230	$	110,752	$	—		$	110,752

(A) Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($149).

(B) Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $49,528. Cash, in the amount of $20,073 is not allocated to any particular segment.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Industry segment results for the twelve months ended December 31, 2004 are:

	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	248,513	$	8,066	$	—	$	256,579	$	—		$	256,579
Sales—related parties		22,000		36		—		22,036		—			22,036
Sales—purchased gas		112,005		—		—		112,005		—			112,005
Other revenue		5,752		58		1,106		6,916		—			6,916
Intersegment revenues		—		178		48,522		48,700		(48,700	)		—
Total Revenue and Other Income	$	388,270	$	8,338	$	49,628	$	446,236	$	(48,700	)	$	397,536
Earnings (Loss) Before Income Taxes	$	120,125	$	877	$	11,686	$	132,688	$	(2	)	$	132,686	(C)
Segment assets	$	412,839	$	20,197	$	281,953	$	714,989	$	8,301		$	723,290	(D)
Depreciation, depletion and amortization	$	21,659	$	693	$	10,537	$	32,889	$	—		$	32,889
Capital expenditures	$	81,889	$	6,517	$	1,347	$	89,753	$	—		$	89,753

(C) Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($2,423). Corporate Adjustments and Eliminations include miscellaneous corporate charges not allocated to individual segments.

(D) Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $47,373. Corporate adjustments and eliminations include deferred tax assets which are not allocated to individual segments.

Industry segment results for the twelve months ended December 31, 2003 are:

	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	172,842	$	5,484	$	—	$	178,326	$	—		$	178,326
Sales—related parties		32,572		—		—		32,572		—			32,572
Other revenue		3,984		61		440		4,485		—			4,485
Intersegment revenues		—		58		49,322		49,380		(49,380	)		—
Total Revenue and Other Income	$	209,398	$	5,603	$	49,762	$	264,763	$	(49,380	)	$	215,383
Earnings (Loss) Before Income Taxes	$	68,427	$	57	$	11,547	$	80,031	$	(20	)	$	80,011	(E)
Segment assets	$	370,543	$	11,617	$	261,262	$	643,422	$	21,213		$	664,635	(F)
Depreciation, depletion and amortization	$	22,992	$	434	$	10,174	$	33,600	$	—		$	33,600
Capital expenditures	$	72,139	$	4,483	$	7,247	$	83,869	$	—		$	83,869

(E) Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($2,932). Corporate Adjustments and Eliminations include miscellaneous corporate charges not allocated to individual segments.

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NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

(F) Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $46,435. Corporate adjustments and eliminations include deferred tax assets which are not allocated to individual segments.

Note 20—Subsequent Event

On January 18, 2006 our registration statement filed with the SEC became effective. CNX Gas Corporation began public trading on the NYSE under the ticker symbol CXG on January 19, 2006.

94

Other Supplemental Information—Supplemental Gas Data (unaudited):

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

Capitalized Costs:

	As of December 31,
	2005			2004
Surface Lands	$	26,573		$	18,240
Mineral Interests		55,621			55,620
Wells and related Equipment (1)		141,959			111,205
Intangible Drilling		312,467			263,403
Gathering Assets		344,355			319,680
Gas Well Closing (1)		7,680			3,217
Other		36			74
Total Property, Plant and Equipment		888,691			771,439
Accumulated Depreciation		(165,144	)		(130,563	)
Net Capitalized Costs	$	723,547		$	640,876
Proportionate Share of Gas Producing Net Property, Plant and Equipment of Unconsolidated Equity Affiliates	$	14,109		$	15,239

(1) Certain other property interests were retained by CONSOL Energy and not conveyed to CNX Gas. These retained assets, which include, for example, assets associated with well plugging, had an aggregate book value of $6,596 at December 31, 2004 and are not material to the business and operations of CNX Gas. CONSOL Energy did not retain any natural gas interests, all of which were transferred to CNX Gas.

Substantially all, or at least 98%, of our capitalized costs are related to proved properties.

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

	For the Twelve Months Ended December 31,
	2005				2004				2003
	Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Property acquisitions	$	8,333	$	20	$	4,190	$	111	$	7,640	$	187
Development		86,273		—		77,478		—		77,801		—
Exploration		19,370		412		5,596		2,902		5,997		4,661
Total	$	113,976	$	432	$	87,264	$	3,013	$	91,438	$	4,848

(*) Includes costs incurred whether capitalized or expensed

Substantially all, or at least 98%, of our acquisition costs are related to proved properties.

95

Results of Operations:

	For the Twelve Months Ended December 31,
	2005						2004						2003
	Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Production Revenue	$	328,488		$	2,814		$	278,669		$	1,587		$	210,898		$	595
Purchased Gas Revenue		275,148			2,561			112,005			1,120			—			152
Total Revenue		603,636			5,375			390,674			2,707			210,898			747
Lifting Costs		26,794			623			23,939			474			20,761			434
Gathering Costs		40,623			168			37,021			172			28,914			170
Royalty Expense		36,641			408			32,914			246			24,200			96
Other Production Costs		17,224			915			16,274			1,153			21,771			1,294
Purchased Gas Costs		278,720			2,434			113,063			1,044			—			351
DD&A		35,039			870			32,889			918			33,600			319
Total Costs		435,041			5,418			256,100			4,007			129,246			2,664
Pre-tax Operating Income		168,595			(43	)		134,574			(1,300	)		81,652			(1,917	)
Income Taxes		65,280			(17	)		52,618			(508	)		31,844			(748	)
Results of Operations excluding Corporate and Interest Costs	$	103,315		$	(26	)	$	81,956		$	(792	)	$	49,808		$	(1,169	)
Net Reserve Quantity (Million Cubic Feet)(1)
Beginning Reserves		1,042,403			2,385			1,002,800			1,581			959,946			559
Revisions		57,575			521			33,539			—			17,484			(200	)
Extensions and Discoveries		77,917			—			53,870			1,006			69,710			1,303
Production		(50,171	)		(234	)		(49,674	)		(202	)		(44,340	)		(81	)
Purchases of Reserves In-Place		—			—			1,868			—			—			—
Sales of Reserves In-Place		—			—			—			—			—			—
Ending Reserves		1,127,724			2,672			1,042,403			2,385			1,002,800			1,581
Proved Developed Reserves:
Beginning of Period		395,152			1,489			352,935			843			329,687			559
End of Period		549,574			2,672			395,152			1,489			352,935			843

* Proved developed and proved undeveloped gas reserves are defined by the Securities and Exchange Commission Rule 4.10(a) of Regulation S-X. Generally, these reserves would be commercially recovered under current economic conditions, operating methods and government regulations.

(1) The information presented below represents estimates of proved natural gas and oil reserves.

CNX Gas’ proved gas reserves are located in the states of Virginia (97.1%), West Virginia (1.0%) and Pennsylvania (1.9%). CNX Gas’ proportionate interest in equity affiliates proved gas reserves is located in the state of Tennessee (100%).

CNX Gas cautions that there are many inherent uncertainties in estimating proved reserve quantities, projecting future production rates, and timing of development expenditures. Accordingly, these estimates are likely to change as future information becomes available. Proved oil and gas reserves are estimated quantities of natural gas and CBM gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those reserves expected to be recovered through existing wells, with existing equipment and operating methods.

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Standardized Measure of Discounted Future Net Cash Flows:

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

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

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

	December 31,
	2005			2004			2003
Future Cash Flows:
Revenues	$	11,675,551		$	6,337,257		$	5,792,348
Production costs		(2,852,033	)		(1,453,364	)		(1,314,691	)
Development costs		(422,315	)		(265,540	)		(307,075	)
Income tax expense		(3,251,265	)		(1,745,782	)		(1,461,785	)
Future Net Cash Flows		5,149,938			2,872,571			2,708,797
Discounted to present value at a 10% annual rate		(3,279,144	)		(1,843,033	)		(1,697,611	)
Total standardized measure of discounted net cash flows	$	1,870,794		$	1,029,538		$	1,011,186

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

	December 31,
	2005			2004			2003
Balance at Beginning of Period	$	1,029,538		$	1,011,186		$	735,181
Net changes in sales prices and production costs		3,539,448			262,723			1,036,699
Sales net of production costs		(234,526	)		(219,937	)		(151,499	)
Net change due to revisions in quantity estimates		632,547			364,456			287,993
Development costs incurred, previously estimated		110,916			87,274			80,455
Changes in estimated future development costs		(267,691	)		(45,739	)		(104,240	)
Net change in future income taxes		(1,505,484	)		(283,997	)		(478,613	)
Accretion of discount and other		(1,433,954	)		(146,428	)		(394,790	)
Total Discounted Cash Flow at End of Period	$	1,870,794		$	1,029,538		$	1,011,186

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Other Supplemental Information—Selected Quarterly Data (Unaudited):

	Three Months Ended
	March 31, 2005		June 30, 2005		September 30, 2005		December 31, 2005
Total Revenue and Other Income	$	106,050	$	111,072	$	176,312	$	220,007
Total Costs and Expense	$	62,919	$	83,442	$	133,497	$	166,865
Total Earnings Before Income Tax	$	43,131	$	27,630	$	42,815	$	53,142
Net Income	$	26,526	$	16,992	$	26,070	$	32,580
Earnings per Share
Basic	$	0.21	$	0.14	$	0.19	$	0.22
Dilutive	$	0.21	$	0.14	$	0.19	$	0.22
Weighted Average Shares Outstanding
Basic		122,896,667		122,896,667		139,294,276		150,833,334
Dilutive		122,988,359		122,988,359		139,416,414		151,003,896

	Three Months Ended
	March 31, 2004		June 30, 2004		September 30, 2004		December 31, 2004
Total Revenue and Other Income	$	71,714	$	85,978	$	120,981	$	118,863
Total Costs and Expense	$	34,914	$	51,864	$	89,992	$	88,080
Total Earnings Before Income Tax	$	36,800	$	34,114	$	30,989	$	30,783
Net Income	$	22,408	$	20,775	$	18,872	$	18,733
Earnings per Share
Basic	$	0.18	$	0.17	$	0.15	$	0.15
Dilutive	$	0.18	$	0.17	$	0.15	$	0.15
Weighted Average Shares Outstanding
Basic		122,896,667		122,896,667		122,896,667		122,896,667
Dilutive		122,988,359		122,988,359		122,988,359		122,988,359

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

CNX Gas, under the supervision and with the participation of its management, including the Company’s principal executive officer and principal financial officer, evaluated the effectiveness of its “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) under the Securities Act of 1934, as amended (the “Exchange Act”), as of the end of the period covered by this 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.

98

Changes in Internal Controls Over Financial Reporting.

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

ITEM 9B. OTHER INFORMATION

None

99

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 “Proposal #1—Nominations for Election of Directors,” “General Information—The Board of Directors and Its Committees—The Board of Directors,” “General Information—The Board of Directors and Its Committees—Membership and Meetings of the Board of Directors and Its Committees” and Section 16(a) “Beneficial Ownership Reporting Compliance” in the Proxy Statement for the annual meeting of shareholders to be held on April 28, 2006 (the “Proxy Statement”).

Executive Officers of CNX Gas Corporation

The following is a list of CONSOL Energy’s executive officers, their ages as of February 15, 2006 and their positions and offices held with CONSOL Energy.

Name	Age	Position
Nicholas J. DeIuliis	37	President and Chief Executive Officer and Director
Ronald E. Smith	57	Executive Vice President and Chief Operating Officer
Gary J. Bench	47	Senior Vice President and Chief Financial Officer
Stephen W. Johnson	47	Senior Vice President, Secretary and General Counsel

Nicholas J. DeIuliis, 37, has been President and Chief Executive Officer and a Director of CNX Gas since its formation on June 30, 2005. Prior to that, Mr. DeIuliis was Senior Vice President—Strategic Planning of CONSOL Energy from November 1, 2004 until August 8, 2005. Prior to that time, Mr. DeIuliis served as Vice President Strategic Planning from April 1, 2002 until November 1, 2004, Director—Corporate Strategy from October 1, 2001 to April 1, 2002, Manager—Strategic Planning from January 1, 2001 to October 1, 2001 and Supervisor—Process Engineering from April 1, 1999 to January 1, 2001, all of which positions he held at CONSOL Energy. Mr. DeIuliis is a Director of the World Coal Institute (a leading coal trade association) and he served as a director of Fairmont Supply Company, a wholly-owned subsidiary of CONSOL Energy until July 2005. Mr. DeIuliis is also a member of the Board of Directors of the Independent Petroleum Association of America and the Carnegie Science Center. Mr. DeIuliis is also a registered engineer in the Commonwealth of Pennsylvania and a member of the Pennsylvania Bar. He received a bachelor’s degree in chemical engineering from Pennsylvania State University and a master’s of business administration and juris doctorate from Duquesne University.

Ronald E. Smith, 57, has been CNX Gas’ Chief Operating Officer since June 30, 2005 and an Executive Vice President since December 5, 2005. Prior to that, Mr. Smith served as Executive Vice President—Gas Operations, Land Resources and Engineering Services of CONSOL Energy from April 1, 1992 to August 8, 2005. Mr. Smith joined CONSOL Energy in 1972. Mr. Smith has held numerous operating and management positions in various coal segments since he joined CONSOL Energy. Mr. Smith received a bachelor’s degree in Mining Engineering from Virginia Polytechnical Institute and State University and received that university’s distinguished alumnus award in 1998.

Gary J. Bench, 47, has been CNX Gas’ Chief Financial Officer since June 30, 2005 and became a Senior Vice President on December 5, 2005. Prior to that, Mr. Bench served as Vice President—Tax of CONSOL Energy from April 11, 2005 to August 8, 2005. Prior to that time, Mr. Bench was Controller—Tax from June 1, 2002 to April 11, 2005 and General Manager—Tax from July 1, 1999 to June 1, 2002, all of which positions he held at CONSOL Energy. Mr. Bench joined CONSOL Energy in 1985. Mr. Bench is also a member of the American Institute of Certified Public Accountants, the Pennsylvania Institute of Certified Public Accountants and the Tax Executive Institute. Mr. Bench received his bachelor’s degree in accounting from Indiana University of Pennsylvania and a master’s in taxation from Robert Morris University.

100

Stephen W. Johnson, 47, has been General Counsel of CNX Gas since September 1, 2005. He was named Senior Vice President as of December 5, 2005. Prior to joining CNX Gas, he was a partner since 2001 in the Business and Regulatory Group at Reed Smith LLP, an international law firm with about 1,000 lawyers. From 1984 to 2001, Mr. Johnson was with the law firm of Buchanan Ingersoll Professional Corporation. Mr. Johnson has served as corporate, securities and mergers and acquisitions counsel to both public and privately held companies for his entire professional career. Mr. Johnson is Vice Chairman of NEED, a non-profit organization that provides college scholarships to minority students, and a director of Concordia Lutheran Ministries, a non-profit continuing care retirement community serving thousands of elderly persons each year. Mr. Johnson received a bachelor’s degree in history from the University of Virginia and a juris doctor degree from the University of Pittsburgh School of Law.

CNX Gas has adopted a written Code of Employee Business Conduct and Ethics that applies to CNX Gas’ Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer), principal accounting officer or controller and persons performing similar functions. The Code of Employee Business Conduct and Ethics is publicly available on CNX Gas’ website at www.cnxgas.com. If CNX Gas makes any amendments to the code other than technical, administrative, or other non-substantive amendments, or grants any waivers, including implicit waivers, from a provision of the code applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, CNX Gas will disclose the nature of the amendment or waiver, its effective date and to whom it applies on its website or in a report on Form 8-K filed with the Securities and Exchange Commission.

ITEM 11. EXECUTIVE COMPENSATION.

The information required by this Item is incorporated by reference to the information under the captions “General Information—The Board of Directors and Its Committees—Compensation of Directors,” “Executive Compensation and Stock Option Information—Compensation Committee,” “Executive Compensation and Stock Option Information—Executive Compensation,” “Executive Compensation and Stock Option Information—CNX Gas Stock Option Grants,” “Executive Compensation and Stock Option Information—CONSOL Energy Stock Option Grants,” “Executive Compensation and Stock Option Information—Retirement Benefits,” and “Executive Compensation and Stock Option Information—CNX Gas Change in Control Severance Agreements” 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—CNX Gas Stock Options Grants,” “Executive Compensation and Stock Option Information—CONSOL Energy Stock Option Grants” and “General Information—Beneficial Ownership of Securities” in the Proxy Statement.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The information requested by this Item is incorporated by reference to the information under the caption “Executive Compensation and Stock Option Information—Related Party Transactions” 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.

101

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.
(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.

102

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 21st day of February, 2006.

CNX Gas Corporation
By:	/S/    NICHOLAS J. DEIULIIS
	Nicholas J. DeIuliis President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 20th day of February, 2006, by the following persons on behalf of the Registrant in the capacities indicated:

Signature	Title
/S/    PHILIP W. BAXTER         Philip W. Baxter	Chairman of the Board
/S/    NICHOLAS J. DEIULIIS         Nicholas J. DeIuliis	President, Chief Executive Officer and Director (Principal Executive Officer)
/S/    GARY J. BENCH         Gary J. Bench	Chief Financial Officer (Principal Financial and Accounting Officer)
/S/    J. BRETT HARVEY         J. Brett Harvey	Director
/S/    JAMES E. ALTMEYER, SR.         James E. Altmeyer, Sr.	Director
/S/    RAJ K. GUPTA         Raj K. Gupta	Director
/S/    JOHN R. PIPSKI         John R. Pipski	Director
/S/    WILLIAM J. LYONS         William J. Lyons	Director

103

EXHIBIT INDEX

3.1	Amended and Restated Certificate of Incorporation of CNX Gas Corporation(1)
3.2	Amended and Restated Bylaws of CNX Gas Corporation(1)
4.1	Registration Rights Agreement dated August 8, 2005 by and among CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.(1)
4.2	Form of stock certificate(1)
10.1	Summary of Employment Terms for Nicholas J. DeIuliis(2)*
10.2	Offer letter for Ronald Smith(2)*
10.3	Offer letter for Gary J. Bench(1)*
10.4	Offer letter for Stephen W. Johnson(1)*
10.5	CNX Gas Corporation Equity Incentive Plan and form of award agreements thereunder(1)*
10.6.1	Form of Change in Control Agreement for executive officers DeIuliis and Bench(1)*
10.6.2	Form of Change in Control Agreement for executive officers Smith and Johnson(1)*
10.7	Master Separation Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each of the its subsidiaries (other than CNX Gas Corporation and its subsidiaries) and CNX Gas Corporation and its subsidiaries(3)
10.8	Master Cooperation and Safety Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each CEI Subsidiary (as defined therein) and CNX Gas Corporation and each CNX Subsidiary (as defined therein)(3)
10.9	Tax Sharing Agreement dated August 1, 2005 between CONSOL Energy Inc. and CNX Gas Corporation(3)
10.10	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)
10.11	Intercompany Revolving Credit Agreement between CONSOL Energy Inc. and CNX Gas Corporation(3)
10.12	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)
10.13	Summary sheet regarding director compensation(1)
10.14	Purchase/Placement Agreement dated August 1, 2005 by and between CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.(1)
10.15	Credit Agreement dated October 7, 2005 between CNX Gas Corporation, certain of its subsidiaries, and the Lender parties thereto.(4)
10.16	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)
10.17	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)
10.18	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)
10.19	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)

10.20	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)
10.21	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)
10.22	Precedent Agreement dated July 29, 2005 by and between East Tennessee Natural Gas, LLC and CNX Gas Company, LLC.(10)
10.23	Description of the CNX Gas Corporation 2006 Short-Term Incentive Compensation Program(11)*
21	Subsidiaries of CNX Gas Corporation(1)
23.1	Consent of PricewaterhouseCoopers LLP
23.2	Consent of Ralph E. Davis Associates, Inc.
23.3	Consent of Schlumberger Data and Consulting Services
31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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

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

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

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

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

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

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

(8) Incorporated by reference from Exhibit 4.2 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. 1 to the Registration Statement on Form S-1 (file no. 333-127483) filed on December 17, 2005

(11) Incorporated by reference from the second paragraph of Item 1.01 of the Current Report on Form 8-K filed by CNX Gas Corporation on February 10, 2006

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

* Management compensatory contract or arrangement.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statement on Form S-8 (No. 333-131497) of CNX Gas Corporation of our report dated February 20, 2006 relating to the financial statements which appears in this Form 10-K.

/s/ PricewaterhouseCoopers LLP

Pittsburgh, Pennsylvania

February 21, 2006

EX-23.2

Exhibit 23.2

CONSENT OF INDEPENDENT ENGINEERS

Data & Consulting Services Division of Schlumberger Technology Corporation
1310 Commerce Drive Park Ridge 1 Pittsburgh, PA 15275-101 Tel: 412-787-5403 Fax: 412-787-2906

CONSENT OF SCHLUMBERGER DATA & CONSULTING SERVICES

As independent petroleum engineers, we hereby consent to (a) the use of our reserve reports relating to the proved reserves of gas and oil (including coalbed methane) of CNX Gas Corporation (and/or its predecessor(s) in interest) as of December 31, 2005, 2004 and 2003 and as of March 31, 2005, and (b) the references to us as experts, in each case, in (x) CNX Gas Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, and (y) all of CNX Gas Corporation’s current and future registration statements filed with the U.S. Securities and Exchange Commission, including all pre-effective and post-effective amendments thereto including by incorporation by reference, including without limitation, CNX Gas Corporation’s Registration Statement on Form S-8 (file no. 333-131497) and CNX Gas Corporation’s Registration Statement on Form S-1 (file no. 333-127483).

We further wish to advise that we are not employed on a contingent basis and that at the time of the preparation of our report, as well as at present, neither Schlumberger Data & Consulting Services nor any of its employees had, or now has, a substantial interest in CNX Gas Corporation or any of its subsidiaries, as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.

SCHLUMBERGER DATA & CONSULTING SERVICES

/s/ Joseph H. Franz, Jr.

Date: February 20, 2006

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT ENGINEERS

CONSENT OF RALPH E. DAVIS ASSOCIATES, INC.

As independent petroleum engineers, we hereby consent to (a) the use of our reserve reports relating to the proved reserves of gas and oil (including coalbed methane) of CNX Gas Corporation (and/or its predecessor(s) in interest) as of December 31, 2004 and 2003, and (b) the references to us as experts, in each case, in (x) CNX Gas Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005, and (y) all of CNX Gas Corporation’s current and future registration statements filed with the U.S. Securities and Exchange Commission, including all pre-effective and post-effective amendments thereto including by incorporation by reference, including without limitation, CNX Gas Corporation’s Registration Statement on Form S-8 (file no. 333-131497) and CNX Gas Corporation’s Registration Statement on Form S-1 (file no. 333-127483).

We further wish to advise that we are not employed on a contingent basis and that at the time of the preparation of our report, as well as at present, neither Ralph E. Davis associates, Inc. nor any of its employees had, or now has, a substantial interest in CNX Gas Corporation or any of its subsidiaries, as a holder of its securities, promoter, underwriter, voting trustee, director, officer or employee.

RALPH E. DAVIS ASSOCIATES, INC.

/s/ Allen C. Barron

Allen C. Barron, P.E.

Date: February 20, 2006

1717 St. James Place, Suite 460    Houston, Texas 77056    Office 713-622-8955    Fax 713-626-3664    www.ralphedavis.com

Worldwide Energy Consultants Since 1924

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Nicholas J. DeIuliis, certify that:

(1) I have reviewed this report on Form 10-K of CNX Gas Corporation;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. (Paragraph omitted pursuant to SEC Release Nos. 33-8238 and 34-47986)

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2006

/s/    NICHOLAS J. DEIULIIS        

Nicholas J. DeIuliis

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Gary J. Bench, certify that:

(1) I have reviewed this report on Form 10-K of CNX Gas Corporation;

(2) Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

(3) Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

(4) The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)), and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. (Paragraph omitted pursuant to SEC Release Nos. 83-8238 and 34-47986);

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

(5) The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2006

/s/    GARY J. BENCH        

Gary J. Bench

Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATIONS

I, Nicholas J. DeIuliis, President and Chief Executive Officer (principal executive officer) of CNX Gas Corporation (the “Registrant”), certify that to my knowledge, based upon a review of the Annual Report on Form 10-K for the period ended December 31, 2005, of the Registrant (the “Report”):

(i) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: February 21, 2006

/s/    NICHOLAS J. DEIULIIS        

Nicholas J. DeIuliis

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATIONS

I, Gary J. Bench, Chief Financial Officer (principal financial officer) of CNX Gas Corporation. (the “Registrant”), certify that to my knowledge, based upon a review of the Annual Report on Form 10-K for the period ended December 31, 2005, of the Registrant (the “Report”):

(i) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(ii) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

Date: February 21, 2006

/s/    GARY J. BENCH        

Gary J. Bench

Chief Financial Officer