Edgar Filing: CNX Gas CORP

Incremental Decrease in Pre-tax Income Assuming a
Hypothetical Price Change of:

(In millions)

Natural Gas (1)

Amendment No. 4 to Form S-1

As filed with the Securities and Exchange Commission on December 16, 2005

Registration No. 333-127483

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 4

FORM S-1

Registration Statement

Under

The Securities Act of 1933

CNX GAS CORPORATION

(Exact name of registrant as specified in its charter)

Delaware

1311

20-3170639

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial Classification Code Number)

(I.R.S. Employer

Identification Number)

4000 Brownsville Road

South Park, PA 15129

(412) 854-6719

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Nicholas J. DeIuliis

Chief Executive Officer

4000 Brownsville Road

South Park, PA 15129

(412) 854-6719

(Name and address, including zip code, and telephone number, including area code, of agent for service)

Copies of all communications to:


Stephen W. Johnson, Esq.	Lewis U. Davis, Jr., Esq.	Mark Zvonkovic, Esq.
General Counsel	Jeremiah G. Garvey, Esq.	Elisabeth Cappuyns, Esq.
CNX Gas Corporation	Buchanan Ingersoll PC	Akin Gump Strauss
4000 Brownsville Road	One Oxford Centre	Hauer & Feld LLP
South Park, PA 15129	301 Grant Street, 20th Floor	590 Madison Avenue
(412) 854-6719	Pittsburgh, PA 15219	New York, NY 10022
	(412) 562-8800	(212) 872-8008

Approximate date of commencement of proposed sale to the public: From time to time after the effective date of this registration statement.

If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, as amended (the “Securities Act”) please check the following box. x

If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If delivery of the prospectus is expected to be made pursuant to rule 434, please check the following box. ¨

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to such Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. These securities may not be sold until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where such offer or sale is not permitted.

Subject to completion

Preliminary prospectus, dated , 2005

PROSPECTUS

LOGO

27,936,667 SHARES OF

COMMON STOCK

This prospectus relates to up to 27,936,667 shares of the common stock of CNX Gas Corporation, which may be offered for sale by the selling stockholders named in this prospectus. The selling stockholders acquired the shares of common stock offered by this prospectus in a private placement. We are registering the offer and sale of the shares of common stock to satisfy registration rights we granted to the selling stockholders.

We are not selling any shares of common stock under this prospectus and will not receive any proceeds from the sale of common stock by the selling stockholders. The shares of common stock to which this prospectus relates may be offered and sold from time to time directly by the selling stockholders or alternatively through underwriters or broker-dealers or agents. The shares of common stock may be sold in one or more transactions, at fixed prices, at prevailing market prices at the time of sale or at negotiated prices. Because all of the shares being offered under this prospectus are being offered by selling stockholders, we cannot currently determine the price or prices at which our shares of common stock may be sold under this prospectus. Prior to the date of this prospectus, we are aware that some of our shares of common stock have been sold in private resale transactions. We understand those sales have been reported to the PORTAL^® Market. To our knowledge, the most recent price at which shares were resold was $20.73 per share on October 7, 2005. Future prices will likely vary from that price and these sales may not be indicative of prices at which our common stock will trade. Until our shares of common stock are listed on the NYSE, we expect that the selling stockholders will sell their shares at prices between $19.75 and $21.75, if any shares are sold. Please read “Plan of Distribution.”

If the shares are to be sold by transferees of the selling stockholders under this prospectus, we must file a post-effective amendment to the registration statement that includes this prospectus or a prospectus supplement, amending the list of selling stockholders to include the transferee as a selling stockholder. Upon being notified by a selling stockholder that it intends to use an agent or principal to sell their shares, a post-effective amendment to the registration statement that includes this prospectus will be filed, naming the agent or principal as an underwriter and disclosing the compensation arrangement. All selling stockholders are subject to Regulation M and are precluded from engaging in any short selling activities prior to effectiveness and for as long as they are participants in the offering. See “Plan of Distribution.”

Prior to this offering, there has been no public market for our common stock. We have received approval from the New York Stock Exchange to list our common stock on the New York Stock Exchange under the symbol “CXG.”

Investing in our common stock involves risks. You should read the section entitled “ Risk Factors” beginning on page 10 for a discussion of certain risk factors that you should consider before investing in our common stock.

You should rely only on the information contained in this prospectus or any prospectus supplement or amendment. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined whether this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is , 2005

ADDITIONAL INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act of 1933 with respect to the common stock offered in this prospectus. This prospectus omits certain information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to CNX Gas Corporation and the common stock offered in this prospectus, reference is made to such registration statement, exhibits and schedules. Statements contained in this prospectus as to the contents of any contract or other document referred to are not necessarily complete, and in each instance reference is made to the copy of such contract or other document filed as an exhibit to the registration statement, each such statement being qualified in all respects by such reference.

The registration statement, including the exhibits and schedules filed therewith, may be inspected free of charge at the public reference facilities maintained by the SEC at Room 1580, 100 F Street, N.E., Washington, D.C. 20549. Copies of such material can be obtained from the Public Reference Section of the SEC, Room 1580, 100 F Street, N.E., Washington, D.C. 20549 at prescribed rates and from the SEC’s Internet site at http://www.sec.gov. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. We intend to list our common stock on the New York Stock Exchange. Reports, proxy statements and other information concerning CNX Gas Corporation can be inspected at the public reference facilities and internet site of the SEC referred to above.

TABLE OF CONTENTS


		Page
Summary		1
The Offering		7
Summary of Financial, Reserve and Operating Data		8
Risk Factors		10
Cautionary Statement Concerning Forward-Looking Statements		21
Use of Proceeds		21
Dividend Policy		22
Selected Financial and Operating Data		23
Management’s Discussion and Analysis of Results of Operations and Financial Condition		26
Business		57
Management		78
Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management		94
Security Ownership of Certain Beneficial Owners and Management		103
Selling Stockholders		104
Description of Capital Stock		118
Plan of Distribution		123
Registration Rights		126
Validity of Shares		128
Experts		128
Glossary of Natural Gas and Coal Terms		G-1
Index to Financial Statements		F-1
Appendix A: Reserve Estimates		A-1

SUMMARY

This summary highlights selected information from this prospectus but does not contain all information that you should consider before investing in the shares. You should read this entire prospectus carefully, including the “Risk Factors” beginning on page 10 and the financial statements included elsewhere in this prospectus. In this prospectus, we refer to CNX Gas, its subsidiaries and predecessors as “we,” “our,” or “our company.” CNX Gas is a recently formed subsidiary of CONSOL Energy which owns, operates and conducts the coalbed methane (in this prospectus we sometimes refer to coalbed methane as CBM) and other gas business previously conducted by CONSOL Energy and its subsidiaries. Except as otherwise noted or unless the context otherwise requires, (i) the information in this prospectus 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 its 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 March 31, 2005, unless otherwise indicated. The estimates of our proved reserves as of December 31, 2004, 2003 and 2002 included in this prospectus 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 March 31, 2005 included in this prospectus are based on a reserve report prepared by Schlumberger Data and Consulting Services. A summary of this report is attached to this prospectus as Appendix A. 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 the royalty owners’ 1/8^th interest in this prospectus. We use the word “net” to indicate when a number does not include the royalty owners’ interest. We have provided definitions for some of the industry terms used in this prospectus in the “Glossary of Natural Gas and Coal Terms.”

About CNX Gas

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. We have acquired all of CONSOL Energy’s rights to CBM associated with 4.5 billion tons of coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other western basins. As of March 31, 2005, we had 1,093.4 Bcfe of net proved reserves with a PV-10 value of $1,837.1 million and our standardized GAAP measure of discounted future net cash flows attributable to our proved reserves was approximately $1,157.0 million. Our proved reserves are approximately 99% CBM and 47.6% proved developed. We believe that we are the second largest gas producer in the Appalachian Basin with net sales of 48.6 Bcf for the year ended December 31, 2004. 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, 98% of our proved reserves are located in Central Appalachia where we have the right to develop approximately 296,000 net CBM acres. As of August 12, 2005, we had developed 38% of our Central Appalachian CBM acreage. In Northern Appalachia, we have the rights to develop approximately 408,000 net CBM acres of which only 7% are currently classified as developed. Our undeveloped CBM acreage contains approximately 2,431 drilling locations. In addition to our CBM activities, we participate in two joint ventures that target conventional development opportunities on approximately 423,000 gross acres throughout the Appalachian Basin. Our conventional acreage position is 99% undeveloped and contains approximately 6,434 drilling locations.

We began extracting CBM in 1982 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.

Areas of Operation

We operate in these principal areas of the Appalachian Basin:

•

Central Appalachia—We extract CBM from the Pocahontas #3 seam and related coal seams associated with Pennsylvanian sandstones and shales. These coal seams have an aggregate reservoir pay zone ranging from approximately 15 to 40 feet. We have the right to extract CBM in the region from a total of approximately 296,000 net CBM acres. This acreage contains most of the 353 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. Nearly all of our proved reserves in this region exist within 148,000 net CBM acres. CONSOL Energy operates mines in the Pocahontas #3 seam and about 27% of our daily gas production in this region is the result of related mining activity. In total, we have identified an additional 1,697 CBM drilling sites.

We are also exploring for conventional natural gas on 149,820 gross acres at depths of up to 6,500 feet in Upper Devonian and Mississippian sandstones, shales and limestones. This exploration is conducted through a joint-venture, of which we own a 50% interest. As of August 12, 2005 we have participated in the drilling of 22 wells. In total, we have an inventory of approximately 1,300 conventional drilling locations on this acreage.

Through subsidiaries, we also own and operate two gathering lines with an aggregate throughput capacity of 250 mmcf per day, and we own a 50% interest in an 88 megawatt electricity generation facility fueled with CNX Gas coalbed methane.

•

Northern Appalachia—We recently began extracting CBM from the Pittsburgh #8 and related seams of the Conemaugh Formation. CONSOL Energy conducts extensive mining activity in this area. We have the right to extract CBM in this region from approximately 408,000 net CBM acres. This acreage contains most of the 2.6 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. At March 31, 2005, we had 21.7 Bcf of proved reserves in this area. We operate four vertical-to-horizontal and 116 gob wells in this area and have an inventory of 734 additional vertical-to-horizontal drilling locations.

•

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 206,364 gross leasehold acres in the region. At March 31, 2005, we had 3.1 Bcfe of proved reserves in this area. As of August 12, 2005, we have 38 gross wells that are operating. In total, we have an inventory of approximately 5,134 conventional gas drilling locations on this acreage.

•

Illinois and Other Western Basins—We have acquired all of CONSOL Energy’s rights associated with CBM from approximately 1.6 billion tons of 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.

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 the 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 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.

Summary of Appalachian Basin Properties as of March 31, 2005


	Central Appalachia		Northern Appalachia		Tennessee		New York	Total
Estimated Net Proved Reserves (Bcfe)	1,068.6		21.7		3.1		—	1,093.4
Percent Developed (1)	46.7	%	82.4	%	100.0	%	—	47.6	%
Net Producing Wells	1,565.5		124		34.5		—	1,724
No. of Drill Sites Available	2,997		734		5,134		—	8,865
Net Exploration Wells	—		4		34.5		—	38.5

	Central Appalachia		Northern Appalachia		Tennessee		New York	Total		Percent of Total
Net Proved Developed CBM Acres	113,500		27,991		—		—	141,491		12.6	%
Net Proved Undeveloped CBM Acres	34,500		3,840		—		—	38,340		3.4
Net Unproved CBM Acres (2)	148,000		376,000		—		—	524,000		46.4

Total Net CBM Acres	296,000		407,831		—		—	703,831		62.4

Gross Proved Developed Conventional Acres	2,780		—		1,520		—	4,300		0.4
Gross Proved Undeveloped Conventional Acres	—		—		—		—	—		—
Gross Unproved Conventional Acres	149,820		—		206,364		62,500	418,684		37.2

Total Gross Conventional Acres	152,600		—		207,884		62,500	422,984		37.6

Total Acres	448,600		407,831		207,884		62,500	1,126,815		100.0	%

(1)	We estimate the cost to fully develop our proved undeveloped reserves excluding abandonment is $319.7 million (in 2005 dollars).

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

As described in “Business—Areas of Operation” and “Business—Ownership of Mineral Rights,” 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 Joint Venture Interests as of March 31, 2005


Area	Type	Joint Venture Partners	Acreage	Working Interest	How Acquired
Central Appalachia	Conventional	Triana	149,820 Gross Conventional Acres	50%	Contributed by CONSOL Energy
Northern Appalachia Tennessee	N/A Conventional	None Atlas America, Inc.	N/A 207,884 Gross Conventional Acres	N/A 50%	N/A 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	62,500 Gross Conventional Acres	25%	By purchase of working interest

CBM Extraction Techniques

We employ a variety of advanced techniques that work in conjunction with the mining process to extract a greater percentage of the CBM from the coal seam than the application of conventional development methods. We have developed a variety of techniques to extract CBM based on regional differences in geology.

Central Appalachia

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 ranges from 5 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 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 1,369 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.

About 63% of our Central Appalachian CBM is produced by drilling a vertical wellbore into the Pocahontas #3 and overlying coal seams and fracturing these seams in multiple stages in order to stimulate gas to flow to the pipe. We refer to this as a “frac well” and currently have 1,156 frac wells operating in Central Appalachia. Where mining is taking place, we also can extract gas by drilling wells into the large fracture zone that is created as the mining equipment removes the main coal seam, causing the associated thinner seams above to collapse into the void left by mining. This fractured area is referred to as “gob” and the wells we drill into the gob are referred to as “gob wells.” In addition, we drill wells horizontally from inside the mine into the coal reserve blocks, called “panels,” that are about to be mined and into coal on the perimeter of the mine. The horizontal wells drilled from the perimeter of the mine may extend as much as 5,000 feet. In the aggregate, gob wells and horizontal wells account for approximately 37% of our CBM production in Central Appalachia and result in an estimated 80% to 85% recovery of gas reserves in place.

Northern Appalachia

We have the right to extract CBM in this region from approximately 408,000 net CBM acres, which contain most of the 2.6 billion tons of 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 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 is a pay zone of thinner 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 7,443 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.

Because of differences in geology, we have found that alternative extraction techniques in this region are more effective than frac wells for producing gas. We have developed advanced well designs that utilize vertical-to-horizontal drilling techniques. Our design includes a vertical wellbore that is intersected by a second well that has three horizontal lateral sections in the coal. This design creates as much as 15,000 feet of productive well length. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region.

Recent Drilling Activity (net wells)


	2005 (Est.)		2004		2003		2002
CBM (frac, gob, horizontal)		186		228		256		207
Conventional		2		12		24		12

Total Wells		188		240		280		219

Completion %		—		100		99		100
Total Capital Expenditures (in thousands)	$	85,724	$	89,753	$	83,869	$	61,705

Our Relationship with CONSOL Energy

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

•

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

•

Allows 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

•

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

The success of our operations substantially depends upon rights we receive 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 provide us certain corporate staff services, provide us a working capital line of credit, and coordinate our tax filings.

We were incorporated in June 2005 as a Delaware corporation. Our principal executive office is located at 4000 Brownsville Road, South Park, PA 15129.

Recent Developments

Buchanan Mine Fire. On February 14, 2005, CONSOL Energy’s Buchanan Mine in southwest Virginia experienced a cave-in behind the longwall mining equipment that ignited methane that is believed to have started a fire underground. As a result, the mine was sealed on February 16, 2005. Gas production associated with mining activity was reduced because of the idling of the mine and because of the temporary shutdown of certain gob gas wells. On account of the shutdown of the Buchanan Mine, our gas production through June 30, 2005 was impaired by approximately 3.6 Bcf (gross). On May 14, 2005, the mine fans began to ventilate the mine after company officials concluded that there was no longer any fire underground. On May 23, 2005, mine rescue teams entered the mine to begin a thorough investigation of the working areas of the mine, making necessary repairs, such as the repairs to the ventilation system. As of May 23, 2005, approximately 15 mmcf per day (gross) of gas production had been restored. On June 2, 2005, CONSOL Energy announced that mine rescue teams had completed their exploration of the mine and had found only slight damage. Regular mine crews have repaired the damage and production with longwall mining equipment resumed on June 16, 2005.

Buchanan Skip Hoist. On September 19, 2005 CONSOL Energy announced that it idled the Buchanan Mine following an incident that damaged the mine’s skip hoist mechanism, which is used to lift coal vertically from the bottom of the mineshaft to the surface. As a result of the mine being idled, our gob gas production was impacted. Through November 30, 2005, we estimate that we have lost .7 Bcf of production as a result of this incident, an amount which is not material to our gas production in 2005. We intend to make a business interruption insurance claim for any lost profits we incur after a 45-day waiting period from the date of the incident. There can be no assurance that we will obtain any recovery from our insurance carrier. CONSOL Energy has completed repairs to the skip hoist and on December 13, 2005 resumed production at the mine. We do not expect that this incident will have a continuing impact on our gob gas production at the mine in the future.

Transportation Considerations. Our gas production moves to market through major pipeline facilities operated by other companies. Currently, our Central Appalachia gas production has access to northeastern U.S. markets through a single interstate pipeline. Recently, we have experienced limited transportation restrictions on that pipeline during periods of low demand for natural gas. We experienced a curtailment of approximately 1.1 Bcf (gross) through September 30, 2005 due to transportation restrictions. We have purchased, at additional cost to us, firm transportation contracts with the pipeline operator during those periods. In addition, because we have limited capacity to store the gas we produce, we have vented to the atmosphere small quantities of our gas when transportation was not available. However, at times when our power generating system would otherwise be idle and when we have transportation constraints, we have operated the generating facility, consuming some of our gas, in order to avoid venting gas to the atmosphere.

We expect to create transportation alternatives through certain transportation agreements with a second interstate pipeline operator, East Tennessee Natural Gas, LLC (in this prospectus we refer to East Tennessee Natural Gas, LLC as East Tennessee), a subsidiary of Duke Energy Corporation (in this prospectus we refer to Duke Energy Corporation as Duke Energy). These agreements require the construction by East Tennessee of an approximately 32-mile lateral pipeline to our gas field in Virginia from East Tennessee’s interstate pipeline system (in this prospectus we refer to East Tennessee’s interstate pipeline system as ETNG). Called Jewell Ridge, this proposed lateral pipeline currently is in the filing process with the Federal Energy Regulatory Commission and 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 East Tennessee at pre-determined fixed rates. We anticipate that the present value of our payments under the 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.

$200 Million Credit Facility. Effective as of October 7, 2005, we entered into a new $200 million credit agreement with a group of lenders. See “Business—New Credit Facility.”

THE OFFERING

Common stock offered by selling stockholders

27,936,667 shares

Common stock outstanding after this offering

150,833,334 shares (1)

Listing

Upon the effectiveness of the registration statement to which this prospectus is a part our shares will be listed on the NYSE under the symbol “CXG”.

Dividend policy

We do not expect to pay dividends in the near future.

Use of proceeds

We will not receive any proceeds from the sale of shares of common stock by the selling stockholders.

Risk factors

For a discussion of factors you should consider in making an investment, see “Risk Factors.”

(1)

The number of common shares outstanding after the offering, excluding all shares of common stock underlying equity awards granted to management, directors and certain employees pursuant to the CNX Gas Equity Incentive Plan. See “Management—CNX Gas Equity Incentive Plan” for a more detailed description of the grant of these shares and the restrictions imposed on them.

SUMMARY OF FINANCIAL, RESERVE AND OPERATING DATA

The following table shows our historical financial, reserve and operating data for, and as of the end of, each of the periods indicated. Our historical results are not necessarily indicative of the results that may be expected for any future period. The following 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 prospectus.


STATEMENT OF INCOME DATA (In thousands)	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
STATEMENT OF INCOME DATA (In thousands)	Nine Months Ended September 30, 2005			2004			2003			2002
Total revenue and other income	$	393,434		$	397,536		$	215,383		$	150,953
Operating expenses		248,123			223,211			95,646			69,429
Equity in (earnings) loss of affiliates		220			2,423			2,932			3,312
Selling, general and administrative		5,632			6,327			3,194			1,140
Depreciation, depletion and amortization		25,883			32,889			33,600			34,368

Earnings before income taxes and cumulative effect of change in accounting		113,576			132,686			80,011			42,704
Income taxes		43,988			51,898			31,202			16,677
Cumulative effect of change in accounting for gas well closing costs (net of tax impact of $1,879)		—			—			2,905			—

Net income	$	69,588		$	80,788		$	51,714		$	26,027


BALANCE SHEET DATA (In thousands)	At September 30, 2005			At December 31,
BALANCE SHEET DATA (In thousands)	At September 30, 2005			2004			2003			2002
Working capital (deficiency)	$	4,753		$	(25,769	)	$	(7,971	)	$	2,868
Total assets		826,321			723,290			664,635			598,236
Long-term debt (including current portion)		—			—			—			—
Stockholders’ equity		628,891			462,556			464,232			468,617

CASH FLOW STATEMENT DATA (In thousands)	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
CASH FLOW STATEMENT DATA (In thousands)	Nine Months Ended September 30, 2005			2004			2003			2002
Net cash provided by operating activities	$	124,896		$	175,350		$	143,133		$	88,643
Net cash used in investing activities		(72,904	)		(93,114	)		(90,605	)		(101,472	)
Net cash (used in) provided by financing activities		(22,439	)		(82,237	)		(52,526	)		12,831

OTHER OPERATING DATA	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
OTHER OPERATING DATA	Nine Months Ended September 30, 2005			2004			2003			2002
Gas:
Net sales volume (Bcf) (1)		36.10			48.60			44.46			41.30
Average sales price excluding effects of financial settlements ($ per mcf) (1)	$	5.92		$	5.41		$	4.31		$	3.17
Average sales price including effects of financial settlements ($ per mcf) (1)	$	5.56		$	5.00		$	4.14		$	3.17
Total average costs ($ per mcf) (1)	$	2.65		$	2.40		$	2.43		$	2.25
Expenses: (per mcf) (1)
Lifting	$	0.54		$	0.50		$	0.48		$	0.40
Gathering & compression	$	0.71		$	0.68		$	0.65		$	0.61
Firm transportation	$	0.12		$	0.09			—			—
General & administrative	$	0.17		$	0.14		$	0.08		$	0.03
Depreciation, depletion & amortization	$	0.74		$	0.70		$	0.76		$	0.84

	Three Months Ended March 31, 2005			Twelve Months Ended December 31,
	Three Months Ended March 31, 2005			2004			2003			2002
Net estimated proved reserves (Bcfe) (1)(2)		1,093			1,045			1,004			961
Pretax PV-10 value (billions) (4)	$	1.84		$	1.66		$	1.56		$	1.09
Price used for proved reserve PV-10 value (per mcf)	$	7.34		$	6.35		$	6.00		$	4.75
Standardized GAAP measure of net future discounted cash flows (billions) (4)	$	1.16		$	1.03		$	1.01		$	0.74

OTHER FINANCIAL DATA (In thousands)	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
OTHER FINANCIAL DATA (In thousands)	Nine Months Ended September 30, 2005			2004			2003			2002
Capital expenditures	$	70,207		$	89,753		$	83,869		$	61,705
EBIT (3)		113,576			132,686			80,011			42,704
EBITDA (3)		139,459			165,575			113,611			77,072

(1)

For entities that are not wholly owned but in which CNX Gas owns 50% or less, includes a percentage of their net production, sales or reserves equal to CNX Gas’ percentage equity ownership. Knox Energy LLC (in this prospectus we refer to Knox Energy LLC as Knox Energy) makes up the equity earnings data in 2005, 2004, 2003 and 2002. Greene Energy LLC (in this prospectus we refer to Greene Energy LLC as Greene Energy) was part of equity earnings in 2002. Sales of gas produced by equity affiliates were 0.19 Bcf in the nine months ended September 30, 2005, 0.20 Bcf in the twelve months ended December 31, 2004, 0.08 Bcf in the twelve months ended December 31, 2003 and 0.22 Bcf in the twelve months ended December 31, 2002.

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

(3)

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. A more detailed description relating to our use of these financial measures can be found at footnote 4 under “Selected Financial Data.” A reconciliation of EBIT and EBITDA to financial net income is as follows:


(In thousands)	Nine Months Ended September 30, 2005		Twelve Months Ended December 31,
	Nine Months Ended September 30, 2005		2004		2003			2002
Net Income	$	69,588	$	80,788	$	51,714		$	26,027
Add: Interest expense		—		—		—			—
Less: Interest income		—		—		—			—
Less: Cumulative effect of changes in accounting for gas well closing costs, net of income taxes of $1,879		—		—		(2,905	)		—
Add: Income tax expense		43,988		51,898		31,202			16,677

Earnings before interest and taxes (EBIT)		113,576		132,686		80,011			42,704
Add: Depreciation, depletion and amortization		25,883		32,889		33,600			34,368

Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)	$	139,459	$	165,575	$	113,611		$	77,072

(4)

We calculate our PV-10 value in accordance with the following table. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when evaluating acquisition candidates. 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 — discounted future net cash flows.

Reconciliation of PV-10 to Standardized Measure:


	March 31, 2005			2004			2003			2002
Future cash inflows	$	8,025,950		$	6,337,257		$	5,792,348		$	4,615,330
Future Production Costs		(2,628,217	)		(1,453,364	)		(1,314,691	)		(1,311,172	)
Future Development Costs		(358,040	)		(265,540	)		(307,075	)		(283,290	)

Future net cash flows		5,039,693			4,618,353			4,170,582			3,020,868
10% discount factor		(3,202,566	)		(2,963,121	)		(2,613,716	)		(1,930,968	)

PV-10 (Non-GAAP measure)		1,837,127			1,655,232			1,556,866			1,089,900

Undiscounted Income Taxes		(1,940,282	)		(1,745,782	)		(1,461,785	)		(983,172	)
10% discount factor		1,260,156			1,120,088			916,105			628,453

Discounted Income Taxes		(680,126	)		(625,694	)		(545,680	)		(354,719	)
Standardized GAAP measure	$	1,157,001		$	1,029,538		$	1,011,186		$	735,181

RISK FACTORS

Investing in our common stock will be subject to risks, including risks inherent in our business. The value of your investment may decline and could result in a loss. You should carefully consider the following factors as well as other information contained in this prospectus before deciding to invest in our common stock.

Risk Related to Our Business

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;

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the price of foreign imports;

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overall domestic and global economic condition;

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

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weather conditions;

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technological advances affecting energy consumption;

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domestic and foreign governmental regulations;

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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 March 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

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 March 31, 2005 would decrease from $1,837.1 million to $1,802.4 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 March 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:

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unexpected drilling conditions;

•

title problems;

•

pressure or irregularities in geologic formations;

•

equipment failures or repairs;

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fires or other accidents;

•

adverse weather conditions;

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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 2004 and continuing in this year, we have had to curtail production due to shipping capacity limitations on Columbia Gas Transmission Corporation’s (in this prospectus we refer to Columbia Gas Transmission Corporation as Columbia) KA-20 line that transports all 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 another pipeline operator, an affiliate of Duke Energy, 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 or CONSOL Energy may be forced to vent gas from the gob wells and in-mine horizontal wells to the atmosphere to alleviate safety concerns.

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.

We may be unable to retain our existing senior management team and/or our key personnel that has 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 (in this prospectus we refer to Coalfield Pipeline Company as Coalfield Pipeline) (gas pipeline) and Buchanan Generation LLC (in this prospectus we refer to Buchanan Generation LLC as Buchanan Generation) (peaker electrical power generation plant) and in a participation agreement with Kelly Oil & Gas, Inc. (in this prospectus we refer to Kelly Oil & Gas, Inc. as 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 recently reached an agreement with East Tennessee, an affiliate of Duke Energy, whereby East Tennessee would construct and transport gas on a pipeline running from its main trunkline 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.

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 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 thru without jeopardizing mine-safety and a well that will ensure wellbore 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 coalbed methane. For example, a third party recently asserted that several of our drilling techniques infringed several patents held by that person. See “Business-Legal Proceedings.” 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.

We depend on our relationship and numerous arrangements with our principal stockholder, CONSOL Energy.

Our relationship and arrangements with CONSOL Energy could create potential conflicts of interest and limit our ability to increase our production and reserve base. Our intercompany agreements with CONSOL Energy are not the result of arm’s-length negotiations and we are required to coordinate our gas production activities with CONSOL Energy’s mining activities. As a result of these relationships, our business could be adversely affected. See “Risk Factors—Risks Relating to Our Relationship with CONSOL Energy.”

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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management” —“ Master Separation Agreement—Contribution of Assets; Assumption of Liabilities”. 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.

Risks Relating to Our Relationship with CONSOL Energy

Our principal stockholder is in a position to affect our ongoing operations, corporate transactions and other matters, and some of our directors and executive officers may also serve on its board of directors, creating potential conflicts of interest.

Our principal stockholder, CONSOL Energy, owns more than 80% 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 and executive officers 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 as described in “Management—Compensation of Executive Officers,” “—CNX Gas Equity Incentive Plan” and “—CONSOL Energy Equity Incentive Plan.” 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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management—Intercompany Agreements with CONSOL Energy—Master Cooperation and Safety Agreement.”

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

We have entered into agreements with CONSOL Energy which govern various transactions between us and our ongoing relationship, including registration rights, tax sharing and indemnification. All of these agreements were entered into while we were a wholly-owned subsidiary of CONSOL Energy, and were negotiated in the overall context of CONSOL Energy creating CNX Gas. As a result, these agreements were not negotiated at arm’s-length. Accordingly, certain rights of CONSOL Energy, particularly the rights relating to the number of demand and piggy-back registration rights that CONSOL Energy will have, the assumption by us of the registration expenses related to the exercise of these rights, our indemnification of CONSOL Energy for certain liabilities under these agreements, our payment of taxes and the retention of tax attributes may be more favorable to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and 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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management—Intercompany Agreements with CONSOL Energy.”

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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management—Intercompany Agreements with CONSOL Energy.”

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 pasu 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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management—Intercompany Agreements with CONSOL Energy.”

As of the date of this prospectus, 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 prospectus 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. See “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management—CONSOL Energy’s Alternatives for Its Shares of Our Common Stock.” 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 coalbed methane, 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 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 16,769 acres with 282.5 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 more than 25% 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 16,769 acres with 282.5 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, it may no longer have the incentive to conduct its mining activities in a manner that is as efficient for our gas operations. In that event, coordination between us and CONSOL Energy’s mining subsidiaries may be more difficult to accomplish.

Risks Relating to Our Common Stock

An active market for our common stock may not develop and the market price for shares of our common stock may be highly volatile and be subject to wide fluctuations.

Prior to the effectiveness of the registration statement of which this prospectus is a part, we were a private company and there was no public market for our common stock. An active market for our common stock may not develop or may not be sustained. The liquidity of any such market that may develop or the price that our stockholders may obtain for their shares of our common stock is uncertain.

Even if an active trading market develops, the market price or such shares of our common stock may be highly volatile and could be subject to wide fluctuations. Some factors that could negatively affect our share price include:

•

our operating and financial performance and prospects;

•

quarterly variations in the rate of growth of our financial indicators, such as earnings per share, net income and revenues;

•

changes in revenue or earnings estimates or publication of research reports by analysts about us or the exploration and production industry;

•

liquidity and registering our common stock for public resale;

•

actual or anticipated variations in our reserve estimates and quarterly operating results;

•

changes in oil and gas prices;

•

speculation in the press or investment community;

•

sales of our common stock by CONSOL Energy or other stockholders;

•

actions by institutional investors or by CONSOL Energy before its disposition of our common stock;

•

increases in our cost of capital;

•

changes in applicable laws or regulations, court rulings and enforcement and legal actions;

•

changes in market valuations of similar companies;

•

adverse market reaction to any increased indebtedness we incur in the future;

•

additions or departures of key management personnel;

•

actions by our stockholders;

•

general market conditions, including fluctuations in and the occurrence of events or tends affecting the price of natural gas; and

•

domestic and international economic, legal and regulatory factors unrelated to our performance.

Provisions in our organizational documents and Delaware law could delay or prevent a change in control of our company, which may result in reduced prices being obtainable for our common stock.

The existence of some provisions in our organizational documents which become effective if CONSOL Energy no longer owns 50% of our common stock and under Delaware law could delay or prevent a change in control of our company, which may result in reduced prices being obtainable for our common stock. The provisions in our certificate of incorporation and bylaws that could delay or prevent an unsolicited change in control of our company include board authority to issue preferred stock, advance notice provisions for director nominations or business to be considered at a stockholder meeting, prohibition on action by partial written consent and voting provisions requiring the vote of more than a majority of the shares present at a meeting. In addition, after CONSOL Energy no longer owns 50% of our common stock, Delaware law will impose some restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. See “Description of Capital Stock—Preferred Stock” and “Description of Capital Stock—Anti-Takeover effects of Delaware Law”, or “—Certificate of Incorporation and Bylaws.”

We will incur increased costs as a result of being a public company.

As a segment of a publicly-held company, we were not directly responsible for the corporate governance and financial reporting practices and policies required of a publicly-traded company. Following the effectiveness of the registration statement, of which this prospectus is a part, we will be a public company. As a public company, we will incur significant legal, accounting and other expenses that we did not directly incur in the past. In addition, the Sarbanes-Oxley Act of 2002, as well as new rules implemented by the SEC, stock exchanges and/or NASDAQ require changes in corporate governance practices of public companies. We expect these new rules and regulations to increase our legal and financial compliance costs and to make some activities more time-consuming and costly.

Prior to August 2005, CNX Gas was not operated as an entity separate from CONSOL Energy, and, as a result, our historical and as adjusted financial information may not be indicative of CNX Gas’s future financial performance.

Our consolidated financial information assumes that CNX Gas, for the periods presented, had existed as a separate legal entity, and has been derived from the consolidated financial statements of CONSOL Energy. CONSOL Energy has historically provided certain corporate overhead services to CNX Gas and allocated to CNX Gas its portion of those costs. If CONSOL Energy failed to provide those services, CNX Gas would need to hire additional employees or consultants to provide those services. The costs incurred by CNX Gas may increase as a result.

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Various statements in this prospectus, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements. 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 prospectus speak only as of the date of this prospectus; 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.”

USE OF PROCEEDS

We will not receive any of the proceeds from the sale of the shares of common stock offered by this prospectus. Any proceeds from the sale of the shares offered by this prospectus will be received by the selling stockholders.

DIVIDEND POLICY

We do not expect to pay dividends in the near future.

SELECTED FINANCIAL AND OPERATING 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, 2004, December 31, 2003 and December 31, 2002, are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2004 and 2003 and the related consolidated statements of income and cash flows for each of the three years in the period ended December 31, 2004 and the notes thereto appearing herein. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2001, the twelve months ended December 31, 2000 and the nine months ended September 30, 2005 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 prospectus.

CNX GAS AND CONSOLIDATED SUBSIDIARIES

CONSOLIDATED STATEMENT OF INCOME


STATEMENT OF INCOME DATA (In thousands)	Nine Months Ended September 30, 2005		Twelve Months Ended December 31,
STATEMENT OF INCOME DATA (In thousands)	Nine Months Ended September 30, 2005		2004		2003		2002		2001			2000
RESULTS OF OPERATIONS
Sales—Outside	$	223,937	$	256,579	$	178,326	$	139,343	$	119,047		$	150,254
Sales—Related Party		5,325		22,036		32,572		9,542		5,288			5,062
Sales—Purchased Gas		157,545		112,005		—		—		—			—
Other income		6,627		6,916		4,485		2,068		403			4,346

TOTAL REVENUE AND OTHER INCOME		393,434		397,536		215,383		150,953		124,738			159,662

Lifting costs		19,087		23,939		20,761		16,297		13,513			28,369
Gathering and compression costs		29,918		37,021		28,914		24,749		18,759			43,432
Royalty		24,505		32,914		24,200		12,214		10,659			3,061
Purchased gas costs		159,739		113,063		—		—		—			—
Other		14,874		16,274		21,771		16,169		17,863			5,078

Equity in (earnings) loss of affiliates		220		2,423		2,932		3,312		(16,788	)		(11,461	)

Selling, general and administrative		5,632		6,327		3,194		1,140		2,446			972

Depreciation, depletion and amortization		25,883		32,889		33,600		34,368		21,175			15,333

TOTAL COSTS AND EXPENSES		279,858		264,850		135,372		108,249		67,627			84,784

Earnings before income taxes and cumulative effect of change in accounting		113,576		132,686		80,011		42,704		57,111			74,878

Income taxes		43,988		51,898		31,202		16,677		22,330			29,277

Earnings before cumulative effect of change in accounting		69,588		80,788		48,809		26,027		34,781			45,601

Cumulative effect of change in accounting for gas well closing costs (net of tax impact of $1,879)		—		—		2,905		—		—			—

NET INCOME	$	69,588	$	80,788	$	51,714	$	26,027	$	34,781		$	45,601


BALANCE SHEET DATA (In thousands)	At September 30, 2005			At December 31,
BALANCE SHEET DATA (In thousands)	At September 30, 2005			2004			2003			2002			2001			2000
Working capital (deficiency)	$	4,753		$	(25,769	)	$	(7,971	)	$	2,868		$	6,984		$	13,154
Total assets		826,321			723,290			664,635			598,236			527,109			320,183
Short-term debt		—			—			—			—			—			—
Long-term debt (including current portion)		—			—			—			—			—			—
Total deferred credits and other liabilities		125,616			218,641			170,520			114,902			86,701			52,807
Stockholders’ equity		628,891			462,556			464,232			468,617			431,582			264,361

CASH FLOW STATEMENT DATA (In thousands)	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
	Nine Months Ended September 30, 2005			2004			2003			2002			2001			2000
Net cash provided by operating activities	$	124,896		$	175,350		$	143,133		$	88,643		$	63,781		$	40,097
Net cash used in investing activities		(72,904	)		(93,114	)		(90,605	)		(101,472	)		(203,168	)		(154,188	)
Net cash (used in) provided by financing activities		(22,439	)		(82,237	)		(52,526	)		12,831			139,387			114,091

OTHER OPERATING DATA	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
OTHER OPERATING DATA	Nine Months Ended September 30, 2005			2004			2003			2002			2001			2000
Gas:
Net sales volumes (Bcf) (1)		36.10			48.60			44.46			41.30			33.92			25.15
Average sales price excluding effects of financial settlements ($ per mcf) (1)(2)	$	5.92		$	5.41		$	4.31		$	3.17		$	4.07		$	5.72
Total average costs ($ per mcf) (1)	$	2.65		$	2.40		$	2.43		$	2.25		$	2.17		$	3.71

	Three Months Ended March 31, 2005			Twelve Months Ended December 31,
	Three Months Ended March 31, 2005			2004			2003			2002			2001			2000
Net estimated proved reserves (Bcfe) (1)(3)		1,093			1,045			1,004			961			1,023			639

OTHER FINANCIAL DATA (In thousands)	Nine Months Ended September 30, 2005			Twelve Months Ended December 31,
OTHER FINANCIAL DATA (In thousands)	Nine Months Ended September 30, 2005				2004			2003			2002			2001			2000
Capital expenditures	$	70,207		$	89,753		$	83,869		$	61,705		$	211,715		$	179,810
EBIT (4)		113,576			132,686			80,011			42,704			57,111			74,878
EBITDA (4)		139,459			165,575			113,611			77,072			78,286			90,211

(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 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 and for the entire 2000 period. Sales of gas produced by equity affiliates were 0.19 Bcf in the nine months ended September 30, 2005, 0.20 Bcf in the twelve months ended December 31, 2004, 0.08 Bcf in the twelve months ended December 31, 2003, 0.22 Bcf in the twelve months ended December 31, 2002, 5.5 Bcf in the twelve months ended December 31, 2001, and 7.0 Bcf in the twelve months ended December 31, 2000.

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

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

(4)

are not measures of performance calculated in accordance with generally accepted accounting principles, 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 generally accepted accounting principles. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconciliation of EBIT and EBITDA to financial net income is as follows:


(In thousands)	Nine Months Ended September 30, 2005		Twelve Months Ended December 31,
	Nine Months Ended September 30, 2005		2004		2003			2002		2001		2000
Net income	$	69,588	$	80,788	$	51,714		$	26,027	$	34,781	$	45,601
Add: Interest expense		—		—		—			—		—		—
Less: Interest income		—		—		—			—		—		—
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		43,988		51,898		31,202			16,677		22,330		29,277

Earnings before interest and taxes (EBIT)		113,576		132,686		80,011			42,704		57,111		74,878
Add: Depreciation, depletion and amortization		25,883		32,889		33,600			34,368		21,175		15,333

Earnings before interest, taxes and depreciation, depletion and amortization (EBITDA)	$	139,459	$	165,575	$	113,611		$	77,072	$	78,286	$	90,211

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

RESULTS OF OPERATIONS AND FINANCIAL CONDITION

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 coalbed methane gas producer with industry-leading expertise in this type of gas extraction.

We began extracting CBM in 1982 to reduce the gas content in the coal being mined by CONSOL Energy to enhance the safety and efficiency of mining operations. However, as demand and prices for natural gas rose in the United States, we found it advantageous to expand our gas operations beyond those which supported the mining activity. Today, a significant portion of our CBM production comes from wells that are located beyond the five-year mine plan for CONSOL Energy’s mines.

In addition to our CBM extraction operations, we operate gathering lines and other infrastructure that enable us to move our gas to interstate pipelines operated by other companies. Our gathering system currently has available capacity to accommodate our expected CBM production in Central Appalachia during the next several years.

During the last year, growth in gas production in the Appalachian Basin and the increase in shipments of liquefied natural gas from Cove Point on the eastern seaboard have resulted in capacity limits on the Columbia KA-20 line that we use to move our gas to market. We have firm transportation contracts on that line for some of our production, but we have experienced and expect to continue to experience some curtailment of shipments until the summer of 2006.

We expect to have access to an alternate pipeline, Duke Energy’s ETNG, once East Tennessee finishes construction of the Jewell Ridge pipeline, a 32-mile line in Virginia that will connect our gas operations with the ETNG line.

In addition, our ownership position in a gas-fired electric generating facility used to meet peak demand has provided us with a way to mitigate the impact of the curtailments to a certain extent. By its nature, a peaking power facility produces power on an intermittent basis depending upon hourly generating economics. However, we have sold gas to this facility even on days when it might not otherwise run because the overall financial impact on our company is better than if production was curtailed.

Prior to August 8, 2005, we were a wholly-owned subsidiary of CONSOL Energy and our financial results have been incorporated into CONSOL Energy’s financial statements. During the past year, we have developed separate financial statements for CNX Gas that will 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

Three Months Ended September 30, 2005 compared with Three Months Ended September 30, 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	$	83,998	$	68,409	$	15,589		22.8	%
Related Party Sales		1,926		993		933		94.0	%
Purchased Gas Sales		88,288		49,349		38,939		78.9	%
Other Income		2,100		2,230		(130	)	(5.8	)%

Total Revenue and Other Income		176,312		120,981		55,331		45.7	%

Costs and Expenses:
Lifting Costs		6,907		5,929		978		16.5	%
Gathering and Compression Costs		10,696		10,077		619		6.1	%
Royalty		10,042		8,488		1,554		18.3	%
Purchased Gas Costs		89,653		49,752		39,901		80.2	%
Other		5,289		5,096		193		3.8	%
Equity in (Earnings) Loss of Affiliates		88		731		(643	)	(88.0	)%
Selling, General & Administrative		2,151		1,697		454		26.8	%
Depreciation, Depletion & Amortization		8,671		8,222		449		5.5	%

Total Costs and Expenses		133,497		89,992		43,505		48.3	%

Earnings Before Income Taxes		42,815		30,989		11,826		38.2	%
Income Taxes		16,745		12,117		4,628		38.2	%

Net Income	$	26,070	$	18,872	$	7,198		38.1	%

Net income for 2005 was improved primarily due to increased average sales prices and slightly higher production. The increased revenues were offset, in part, by higher costs attributable to increased severance taxes, royalties and gas imbalance 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	$	83,998	$	68,409	$	15,589		22.8	%
Related Party Sales		1,926		993		933		94.0	%
Purchased Gas Sales		88,288		49,349		38,939		78.9	%
Other Income		2,100		2,230		(130	)	(5.8	)%

Total Revenue and Other Income	$	176,312	$	120,981	$	55,331		45.7	%

The increase in gas sales revenue, both outside and related party combined, was primarily due to a higher average sales price per thousand cubic feet and slightly higher production in 2005 compared to 2004.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		14.2		14.0		0.2	1.4	%
Average Gross Sales Price (per mcf)	$	6.05	$	4.94	$	1.11	22.5	%

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 affect of the recent hurricane season has shut-in significant portions of gulf coast gas, increasing the tight supply of gas leading to even higher prices in 2005. Higher sales volumes in the 2005 period were primarily the results of wells coming on line from the on-going drilling program and the results of the enhanced stimulation of existing frac wells (wells drilled into the coal seam). CNX Gas enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. 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 the three months ended September 30, 2005, these financial cash flow hedges represented 17% of our produced gas sales volumes at an average price of $4.88 per thousand cubic feet. These financial cash flow hedges currently are expected to represent 18% of our estimated total 2005 produced sales volumes at an average price of $5.48 per thousand cubic feet. CNX Gas sold 69% of produced gas sales volumes in the 2005 period under fixed price contracts at an average price of $4.62 per thousand cubic feet.

In addition, in order to satisfy obligations to certain customers, we purchased gas from and sold gas to other gas suppliers between the segmentation and interruptible pools on the Columbia pipeline, which 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 gas suppliers.


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		9.8		8.5		1.3	15.3	%
Average Sales Price (per mcf)	$	9.03	$	5.83	$	3.20	54.9	%

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


	2005		2004		Dollar Variance			Percentage Change
Royalty Income	$	1,766	$	1,883	$	(117	)	(6.2	)%
Third Party Gathering Revenue		294		300		(6	)	(2.0	)%
Other Miscellaneous		40		47		(7	)	(14.9	)%

Total Other Income	$	2,100	$	2,230	$	(130	)	(5.8	)%

Royalty income decreased in 2005 compared to 2004 due to lower volumes being produced by third parties. The decrease in volumes was offset, in part, by 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 decreased slightly due to reduced rates received from third parties in 2005 compared to 2004.

Other miscellaneous income decreased for 2005 due to miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs and Expenses

Increased costs and expenses in 2005 were made up of the following components:


	2005		2004		Dollar Variance			Percentage Change
Costs and Expenses:
Lifting Costs	$	6,907	$	5,929	$	978		16.5	%
Gathering and Compression Costs		10,696		10,077		619		6.1	%
Royalty		10,042		8,488		1,554		18.3	%
Purchased Gas Costs		89,653		49,752		39,901		80.2	%
Other		5,289		5,096		193		3.8	%
Equity in (Earnings) Loss of Affiliates		88		731		(643	)	(88.0	)%
Selling, General & Administrative		2,151		1,697		454		26.8	%
Depreciation, Depletion & Amortization		8,671		8,222		449		5.5	%

Total Costs and Expenses	$	133,497	$	89,992	$	43,505		48.3	%

Lifting costs increased due to increased unit costs and higher produced sales volumes.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		14.2		14.0		0.2	1.4	%
Average Lifting Costs (per mcf)	$	0.49	$	0.42	$	0.07	16.7	%

Lifting costs per unit sold increased primarily due to higher severance taxes attributable to higher average sales price received for produced gas. Lifting costs per unit sold also increased due to gas well maintenance expenses in 2005 compared to 2004. Well maintenance fees have increased due to additional wells being serviced in the current year. Gas well maintenance expenses were also increased due to the initiation of an enhancement program on frac wells in an attempt to stimulate additional production during the shut down of Buchanan Mine. Increases in lifting costs were also attributable to higher volumes of produced gas sales in the period-to-period comparison.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		14.2		14.0		0.2	1.4	%
Average Gathering and Compression Costs (per mcf)	$	0.75	$	0.72	$	0.03	4.2	%

The increase in gathering and compression costs per unit was attributable to a $0.03 per mcf increase in power expense as a result of converting several compressors from gas powered to electric powered in the current year. Gathering and compression costs per unit also increased $0.01 per mcf due to the purchase of firm transportation capacity on the Columbia interstate pipeline. Firm transportation has been purchased 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. The purchased fixed capacity on the pipeline for the fourth quarter 2005 represents approximately 46% of our projected production for the same period. These increases were offset, in part, by various transactions, none of which were individually material.

Royalty costs increased primarily due to the 22.5% increase in average sales price per mcf in the period-to-period comparison.


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		9.8		8.5		1.3	15.3	%
Average Purchased Gas Costs (per mcf)	$	9.17	$	5.88	$	3.29	56.0	%

Average costs of purchased gas have increased reflecting the average increase in market price of gas. Volumes of purchased gas have increased due to CNX Gas utilizing higher levels of firm transportation in the 2005 period that required us to purchase from and sell to other gas suppliers.

Other costs and expenses increased due to the following items:


	2005		2004			Dollar Variance			Percentage Change
Imbalance	$	618	$	(12	)	$	630		5,250.0	%
Direct Administration		2,107		1,941			166		8.6	%
Accounts Receivable Securitization Fees		198		487			(289	)	(59.3	)%
Land Rental Fees		182		456			(274	)	(60.1	)%
Well Site General Maintenance		797		879			(82	)	(9.3	)%
Miscellaneous		1,387		1,345			42		3.1	%

Total Other Costs and Expenses	$	5,289	$	5,096		$	193		3.8	%

Gas imbalance on the pipeline 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. The gas imbalance has shifted from an over-delivered position to an under-delivered position in 2005 compared to 2004. The increase in imbalance cost per unit sold was offset by corresponding increases in gas sales revenue.

Direct administration costs have increased in the period-to-period comparison due to higher employee counts in the 2005 period compared to the 2004 period.

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 from CONSOL Energy. Prior to separation, CNX Gas sold eligible receivables to CONSOL Energy’s subsidiary on a discounted basis. The fees above represent the discounted portion on the sale of those receivables.

Land rental fees decreased in 2005 due 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 site general maintenance costs decreased slightly in the period to period comparison, due mostly to changes in the timing of scheduled maintenance in the current year. CNX Gas shifted more of its scheduled maintenance to earlier periods in 2005 to coincide with the production curtailment on the Columbia pipeline. This resulted in maintenance for the current period to be down against the prior period, over which maintenance costs were incurred more ratably.

Miscellaneous costs and expenses increased due to various miscellaneous transactions that occurred in both periods, none of which were individually material.

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


	2005			2004			Dollar Variance			Percentage Change
Buchanan Generation	$	28		$	322		$	(294	)	(91.3	)%
Knox Energy		76			422			(346	)	(82.0	)%
Coalfield Pipeline		(16	)		(13	)		(3	)	23.1	%

Total Equity in (earnings) loss of Affiliates	$	88		$	731		$	(643	)	(88.0	)%

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’s losses were lower in 2005 compared to 2004 primarily due to production increases at the joint venture and additional service revenue. CNX Gas’ portion of the joint venture production was approximately 67 mmcf in 2005 compared to approximately 62 mmcf in 2004. 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 its partner.

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

Selling, general and administrative increased to $2,151 in 2005 from $1,697 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 has increased due to the following items:


	2005		2004		Dollar Variance		Percentage Change
Production	$	5,793	$	5,588	$	205	3.7	%
Gathering		2,878		2,634		244	9.3	%

Total Depreciation, Depletion and Amortization	$	8,671	$	8,222	$	449	5.5	%

The increase in production related depreciation, depletion and amortization was primarily due to a slightly higher unit-of-production rate and higher production volumes 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.

Income Taxes


	2005			2004			Variance		Percentage Change
Earnings Before Income Taxes	$	42,815		$	30,989		$	11,826	38.2	%
Tax Expense	$	16,745		$	12,117		$	4,628	38.2	%
Effective Income Tax Rate		39.1	%		39.1	%

Results of Operations

Nine Months Ended September 30, 2005 compared with Nine Months Ended September 30, 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	$	223,937	$	187,651	$	36,286		19.3	%
Related Party Sales		5,325		20,535		(15,210	)	(74.1	)%
Purchased Gas Sales		157,545		65,419		92,126		140.8	%
Other Income		6,627		5,068		1,559		30.8	%

Total Revenue and Other Income		393,434		278,673		114,761		41.2	%

Costs and Expenses:
Lifting Costs		19,087		16,666		2,421		14.5	%
Gathering and Compression Costs		29,918		26,073		3,845		14.7	%
Royalty		24,505		24,643		(138	)	(0.6	)%
Purchased Gas Costs		159,739		65,969		93,770		142.1	%
Other		14,874		12,718		2,156		17.0	%
Equity in (Earnings) Loss of Affiliates		220		1,882		(1,662	)	(88.3	)%
Selling, General & Administrative		5,632		4,716		916		19.4	%
Depreciation, Depletion & Amortization		25,883		24,103		1,780		7.4	%

Total Cost and Expenses		279,858		176,770		103,088		58.3	%

Earnings Before Income Taxes		113,576		101,903		11,673		11.5	%
Income Taxes		43,988		39,848		4,140		10.4	%

Net Income	$	69,588	$	62,055	$	7,533		12.1	%

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 a production stimulation program, accelerated maintenance fees, firm transportation charges and gas imbalance 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	$	223,937	$	187,651	$	36,286		19.3	%
Related Party Sales		5,325		20,535		(15,210	)	(74.1	)%
Purchased Gas Sales		157,545		65,419		92,126		140.8	%
Other Income		6,627		5,068		1,559		30.8	%

Total Revenue and Other Income	$	393,434	$	278,673	$	114,761		41.2	%

The increase in gas sales revenue, both outside and related party combined, was primarily due to a higher average sales price per thousand cubic feet in 2005 compared to 2004.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		41.0		41.0		0.0	0.0	%
Average Gross Sales Price (per mcf)	$	5.59	$	5.07	$	0.52	10.3	%

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 affect of the recent hurricane season has shut-in significant portions of gulf coast gas, increasing the tight supply of gas leading to even higher prices in 2005. CNX Gas enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. 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 cash flow hedges represented 19% of our produced gas sales volumes for the nine months ended September 30, 2005 at an average price of $5.65 per mcf. These financial cash flow hedges currently are expected to represent 18% of our estimated total 2005 produced sales volumes at an average price of $5.48 per mcf. CNX Gas sold 52% of our produced gas sales volumes in the nine months ended September 30, 2005 under fixed price contracts at an average price of $4.53 per mcf. Despite the loss of 3.6 billion cubic feet related to the Buchanan Mine fire and 1.1 Billion cubic feet related to curtailments on CNX Gas shipment capacity on the Columbia interstate pipeline, sales volumes are virtually unchanged in the 2005 period compared to the 2004 period. CNX Gas was able to offset these production losses from 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 fire.

Due to the potential curtailment on portions of the shipment capacity allocated to CNX Gas, as a result of increased demand for pipeline use on the Columbia interstate gas pipeline, CNX Gas purchased firm transportation capacity on the pipeline during 2005. This arrangement is expected to offset a portion of the expected impact from periodic curtailments. As of September 30, 2005, the purchased firm transportation capacity on the pipeline for the fourth quarter 2005 represents approximately 46% of our projected production for the same period. In April 2005, due to routine maintenance and construction activities, CNX Gas was given notice by Columbia regarding reductions in allowable gas flows. Interruptible gas was completely shut in and our contracted firm transportation flows were reduced by 60%. These reductions resulted in a year to date impact of approximately $6.8 million of reduced revenues. Even though these scheduled reductions were lifted, CNX Gas anticipates that the pipeline constraints will be an on-going issue for the foreseeable future requiring the procurement of firm capacity.


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		20.0		10.9		9.1	83.5	%
Average Sales Price (per mcf)	$	7.87	$	6.02	$	1.85	30.7	%

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


	2005		2004		Dollar Variance		Percentage Change
Royalty Income	$	5,698	$	4,151	$	1,547	37.3	%
Third Party Gathering Revenue		794		784		10	1.3	%
Other Miscellaneous		135		133		2	1.5	%

Total Other Income	$	6,627	$	5,068	$	1,559	30.8	%

Royalty income increased in 2005 compared to 2004 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 slightly due to higher volumes transported through gathering systems for third parties, offset by reduced rates in 2005 compared to 2004.

Other miscellaneous income increased for 2005 due to miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs and Expenses

Increased costs and expenses in 2005 were made up of the following components:


	2005		2004		Dollar Variance			Percentage Change
Costs and Expenses:
Lifting Costs	$	19,087	$	16,666	$	2,421		14.5	%
Gathering and Compression Costs		29,918		26,073		3,845		14.7	%
Royalty		24,505		24,643		(138	)	(0.6	)%
Purchased Gas Costs		159,739		65,969		93,770		142.1	%
Other		14,874		12,718		2,156		17.0	%
Equity in (Earnings) Loss of Affiliates		220		1,882		(1,662	)	(88.3	)%
Selling, General & Administrative		5,632		4,716		916		19.4	%
Depreciation, Depletion & Amortization		25,883		24,103		1,780		7.4	%

Total Costs and Expenses	$	279,858	$	176,770	$	103,088		58.3	%

Lifting costs increased due to increased unit costs, while produced volumes remained flat.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		41.0		41.0		0.0	0.0	%
Average Lifting Costs (per mcf)	$	0.47	$	0.41	$	0.06	14.6	%

Lifting costs per unit sold increased primarily due to higher gas well maintenance expenses in 2005 compared to 2004. Well maintenance fees have increased due to additional wells being serviced in the current year. Gas well maintenance expenses were also increased due to the initiation of an enhancement program on frac wells in an attempt to stimulate additional production during the shut down of Buchanan Mine. Lifting costs per unit sold also increased due to higher real estate taxes related to reassessments of CNX Gas’ property.


	2005		2004		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		41.0		41.0		0.0	0.0	%
Average Gathering and Compression Costs (per mcf)	$	0.73	$	0.64	$	0.09	14.1	%

The increase in gathering and compression costs per unit was attributable to a $0.04 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. The purchased fixed capacity on the pipeline for the fourth quarter 2005 represents approximately 46% of our projected production for the same period. Gathering and compression costs per unit also increased approximately $0.03 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 transactions, none of which were individually material.

Although average gas sales prices increased 10.3%, CNX Gas royalty expense decreased due to finalization of several agreements with lessors that resulted in lower royalty rates.

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 includes a small volume of this type of transaction and, therefore, did not significantly impact the 2004 period results of operations. Purchased gas cost information is as follows:


	2005		2004		Variance		Percentage Change
Purchased Gas Sales Volumes (Bcf)		20.0		10.9		9.1	83.5	%
Average Purchased Gas Costs (per mcf)	$	7.98	$	6.07	$	1.91	31.5	%

Other costs and expenses increased due to the following items:


	2005		2004			Dollar Variance			Percentage Change
Imbalance	$	1,462	$	(202	)	$	1,664		823.8	%
Direct Administration		6,098		5,433			665		12.2	%
Well Site General Maintenance		2,687		2,245			442		19.7	%
Land Rental Fees		298		665			(367	)	(55.2	)%
Accounts Receivable Securitization Fees		1,328		1,377			(49	)	(3.6	)%
Miscellaneous		3,001		3,200			(199	)	(6.2	)%

Total Other Costs and Expenses	$	14,874	$	12,718		$	2,156		17.0	%

Direct administration costs have 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 and accelerated maintenance that was re-scheduled to coincide with the curtailment on the Columbia interstate pipeline.

Land rental fees decreased in 2005 due 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.

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 CONSOL Energy’s subsidiary on a discounted basis. The fees above represent the discounted portion on the sale of those receivables.

Miscellaneous costs and expenses decreased due to various miscellaneous transactions that occurred in both periods, none of which were individually material.

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


	2005			2004			Dollar Variance			Percentage Change
Buchanan Generation	$	171		$	821		$	(650	)	(79.2	)%
Knox Energy		84			1,080			(996	)	(92.2	)
Coalfield Pipeline		(35	)		(19	)		(16	)	(84.2	)

Total Equity in (Earnings) Loss of Affiliates	$	220		$	1,882		$	(1,662	)	(88.3	)%

Knox Energy’s losses were lower in 2005 compared to 2004 primarily due to production increases at the joint venture and additional service revenue. CNX Gas’ portion of the joint venture production was approximately 214 mmcf in 2005 compared to approximately 178 mmcf in 2004. 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 its partner.

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

Selling, general and administrative increased to $5,632 in 2005 from $4,716 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	$	17,252	$	16,200	$	1,052	6.5	%
Gathering		8,631		7,903		728	9.2	%

Total Depreciation, Depletion and Amortization	$	25,883	$	24,103	$	1,780	7.4	%

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.

Income Taxes


	2005			2004			Variance			Percentage Change
Earnings Before Income Taxes	$	113,576		$	101,903		$	11,673		11.5	%
Tax Expense	$	43,988		$	39,848		$	4,140		10.4	%
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.

Quantitative And Qualitative Disclosures About Market Risk

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

CNX Gas uses fixed-price contracts and derivative commodity instruments that qualify as cash-flow hedges under Statement of Financial Accounting Standards No. 133 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 its 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 prospectus.

Sensitivity analyses of the incremental effects on pre-tax income for the nine months ended September 30, 2005 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of September 30, 2005 are provided in the following table:

(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 September 30, 2005, the fair value of these contracts was a net loss of $50.3 million (net of $31.5 million deferred tax), We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

Hedging Volumes

As of September 30, 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
2005 Fixed Price Volumes
Hedged mcf		9,512,690		9,792,893		9,900,508		8,971,574		38,177,665
Weighted Average Hedge Price/mcf	$	5.26	$	4.62	$	4.62	$	4.59	$	4.77

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		1,847,716		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 credit-worthiness 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.

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.

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 from a single day to greater than a year. 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 in the twelve month period 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 in 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 gas 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 covers the November 2004 through October 2006 period and assures 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	0.0		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	%

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 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 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. 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.

Cumulative Effect of Changes in Accounting for Gas Well Closing Costs

Effective January 1, 2003, CNX Gas adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), as required. CNX Gas 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 by approximately $2,085 and total liabilities decreased by 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.

Twelve Months Ended December 31, 2003 compared with Twelve Months Ended December 31, 2002

(Amounts reported in thousands)

Net Income

Net income changed primarily due to the following items:


	2003		2002		Dollar Variance			Percentage Change
Revenue and Other Income:
Outside Sales	$	178,326	$	139,343	$	38,983		28.0	%
Related Party Sales		32,572		9,542		23,030		241.4
Other Income		4,485		2,068		2,417		116.9

Total Revenue and Other Income		215,383		150,953		64,430		42.7

Costs and Expenses:
Lifting Costs		20,761		16,297		4,464		27.4
Gathering and Compression Costs		28,914		24,749		4,165		16.8
Royalty		24,200		12,214		11,986		98.1
Other		21,771		16,169		5,602		34.6
Equity in (Earnings) Loss of Affiliates		2,932		3,312		(380	)	(11.5	)
Selling, General & Administrative		3,194		1,140		2,054		180.2
Depreciation, Depletion & Amortization		33,600		34,368		(768	)	(2.2	)

Total Cost and Expenses		135,372		108,249		27,123		25.1	%


Earnings (Loss) Before Income Taxes & Cumulative Effect of Change in Accounting Principle		80,011		42,704		37,307		87.4

Income Taxes		31,202		16,677		14,525		87.1

Earnings (Loss) Before Cumulative Effect of Change in Accounting		48,809		26,027		22,782		87.5
Cumulative Effect of Change in Accounting		2,905		—		2,905		100.0

Net Income (Loss)	$	51,714	$	26,027	$	25,687		98.7	%

Net income for 2003 was improved primarily due to increased production and increased average sales prices. 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.

Revenue and Other Income

Revenue and other income increased due to the following items:


	2003		2002		Dollar Variance		Percentage Change
Revenue and Other Income:
Outside Sales	$	178,326	$	139,343	$	38,983	28.0	%
Related Party Sales		32,572		9,542		23,030	241.4
Other Income		4,485		2,068		2,417	116.9

Total Revenue and Other Income	$	215,383	$	150,953	$	64,430	42.7	%

The increase in sales revenue, both outside and related party combined, was primarily due to a higher average sales price per mcf and increased volumes sold in 2003 compared to 2002.


	2003		2002		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		50.7		46.9		3.8	8.1	%
Average Gross Sales Price (per mcf)	$	4.16	$	3.17	$	0.99	31.2	%

In 2003, gas market price increases were largely driven by the overall supply/demand imbalance that depleted U.S. storage levels by the end of March 2003 and the subsequent need to refill that storage prior to the start of the next winter heating season. CNX Gas enters into various physical gas supply transactions with our gas marketers, selling gas under short-term multi-month contract nominations generally not exceeding one year. CNX Gas also entered into various swap transactions that qualify as financial cash flow hedges, which existed parallel to the underlying physical transactions. In 2003, these cash flow hedges represented 11% of our total 2003 produced sales volumes at an average price of $4.10 per mcf. These cash flow hedges are expected to represent 24% of our estimated 2004 produced sales volumes at an average price of $5.17 per mcf. CNX Gas sold 90% of its gas sales volumes in 2003 at an average price of $3.99 per mcf compared to 77% of its gas sales volumes in 2002 at $3.16 per mcf under contracts agreed to in prior periods. Higher sales volumes were a result of wells coming on-line from the ongoing drilling program, which allowed CNX Gas to take advantage of increased demand.

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


	2003		2002		Dollar Variance		Percentage Change
Royalty Income	$	3,968	$	2,051	$	1,917	93.5	%
Third Party Gathering Revenue		440		—		440	100.0
Other Miscellaneous		77		17		60	352.9

Total Other Income	$	4,485	$	2,068	$	2,417	116.9	%

Royalty income increased in 2003 compared to 2002 due to increased gas prices. Royalty income received from third parties is calculated as a percentage of the third parties’ sales price.

CNX Gas began transporting gas for a third party through its gathering system in 2003. No third party gas was transported before this time.

Other income increased primarily due to higher volumes of oil sales made in 2003 compared to 2002. The increased volumes were offset, in part, by the reduced price per barrel received for each barrel. Other miscellaneous income also increased due to various miscellaneous transactions that occurred throughout both periods, none of which were individually material.

Costs

Increased cost of goods sold and other charges in 2003 and 2002 were made up of the following components:


	2003		2002		Dollar Variance			Percentage Change
Cost of Goods Sold and Other Charges:
Lifting Costs	$	20,761	$	16,297	$	4,464		27.4	%
Gathering and Compression Costs		28,914		24,749		4,165		16.8
Royalty		24,200		12,214		11,986		98.1
Other		21,771		16,169		5,602		34.6
Equity in (Earnings) Loss of Affiliates		2,932		3,312		(380	)	(11.5	)
Selling, General and Administrative		3,194		1,140		2,054		180.2
Depreciation, Depletion and Amortization		33,600		34,368		(768	)	(2.2	)

Total Cost and Expenses	$	135,372	$	108,249	$	27,123		25.1	%

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


	2003		2002		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		50.7		46.9		3.8	8.1	%
Average Lifting Costs (per mcf)	$	0.41	$	0.35	$	0.06	17.1	%

Lifting costs per unit sold increased primarily due to increased severance tax charges. Severance taxes are calculated as 3% of gas sales price. Due to the 31.2% average sales price increase, severance taxes have increased approximately $0.03 per mcf. Average lifting cost of goods sold and other charges per mcf also increased approximately $0.03 per mcf due to increased gas well maintenance costs. Increased maintenance costs were attributable to the additional wells as a result of the on-going drilling program.

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


	2003		2002		Variance		Percentage Change
Produced Gross Sales Volumes (Bcf)		50.7		46.9		3.8	8.1	%
Average Gathering and Compression Costs (per mcf)	$	0.57	$	0.53	$	0.04	7.5	%

The increase in gathering and compression costs per unit were primarily due to increased maintenance fees in 2003. Maintenance fees increased due to collection system maintenance required due to a rupture in the main gathering line and expenses incurred due to relocation of compressors related to an underground longwall mining unit relocation causing potential subsidence.

Royalty costs increased primarily due to the 31.2% increase in average sales price per mcf in 2003 compared to 2002.

Other costs and expenses increased due to the following items:


	2003		2002			Dollar Variance			Percentage Change
Well Site General Maintenance	$	2,049	$	1,806		$	243		13.5	%
Accounts Receivable Securitization Fees		1,103		—			1,103		100.0
Land Rental Fees		1,003		948			55		5.8
Well Plugging Accretion Expense		450		—			450		100.0
Well Plugging Expense		—		2,207			(2,207	)	(100.0	)
Legal Settlements		5,728		(789	)		6,517		826.0
Miscellaneous		11,438		11,997			(559	)	(4.7	)

Total Other Cost	$	21,771	$	16,169		$	5,602		34.6	%

Well site general maintenance fees increased in 2003 due to the additional wells being maintained as a result of the on-going drilling program.

Accounts receivable securitization fees began in 2003 due to the agreement between CNX Gas and a wholly-owned subsidiary of CONSOL Energy. 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.

Well plugging accretion began in 2003 due to the change in accounting adopted by CNX Gas. (See cumulative effect of the change in accounting discussion that follows). Prior to the adoption of the new accounting standard, CNX Gas accrued for well plugging costs on an estimated units-of-production basis. This amount was reflected as a well plugging expense in the above table.

Legal settlements in 2003 were related to accruals for a settlement that was 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. Pursuant to the 2003 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. Legal settlements in 2002 resulted in a credit to expense for an actualization of accruals booked in prior periods. The actualization was the result of the settlement payment being made in 2002 for a previously accrued royalty dispute. Pursuant to a 2002 court-ordered settlement, CNX Gas paid the difference between CNX Gas’ calculation and the court-approved calculation for royalties on gas production from inception through August 1999.

Miscellaneous costs and expenses changed due to various transactions throughout both periods, none of which were individually material.

Equity in (earnings) loss of affiliates were lower in 2003 compared to 2002 due to the following:


	2003		2002		Dollar Variance			Percentage Change
Buchanan Generation	$	1,173	$	532	$	641		120.5	%
Greene Energy		—		254		(254	)	(100.0	)
Knox Energy		1,644		2,376		(732	)	(30.8	)
Coalfield Pipeline		115		150		(35	)	(23.3	)

Total Equity in Loss of Affiliates	$	2,932	$	3,312	$	(380	)	(11.5	)%

Buchanan Generation’s losses were lower in 2003 compared to 2002 primarily due to an increase in the average price of megawatt hours received by the joint venture. The average price received per megawatt hour

increased by approximately 44% in the period to period comparison due to the unit being run for more megawatt hours in 2003 compared to 2002. This improvement, was offset, in part, by increased fuel charges due to higher average gas sales prices in 2003 compared to 2002.

CNX Gas held a 50% interest in the Greene Energy gas treatment facility until August 2002. CNX Gas purchased the other 50% interest in Greene Energy in August 2002 and, accordingly, began to fully consolidate the activity of this company.

Knox Energy’s losses were lower in 2003 compared to 2002 primarily due to production increases at the joint venture. CNX Gas’ portion of the joint venture production was approximately 93 mmcf in 2003 compared to approximately 45 mmcf in 2002. CNX Gas owns a 50% interest in this joint venture.

Equity in earnings of Coalfield Pipeline improved in 2003 compared to 2002 due primarily to increased volumes transported through their gathering system.

Selling, general and administrative costs increased to $3,194 in 2003 from $1,140 in 2002 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:


	2003		2002		Dollar Variance			Percentage Change
Production	$	23,424	$	25,671	$	(2,247	)	(8.8	)%
Gathering		10,176		8,697		1,479		17.0

Total Depreciation, Depletion and Amortization	$	33,600	$	34,368	$	(768	)	(2.2	)%

Production depreciation, depletion and amortization was improved in 2003 primarily due to a higher ratio of gas production coming from mine gob areas which have lives generally less than twelve months long. As a result, the costs to produce these areas are expensed instead of capitalized and then amortized. This gob gas production is not included in the calculation of units-of-production depreciation or depletion for capitalized gas costs. The reduction in depreciation, depletion and amortization was offset, in part, by additional depreciation attributable to new assets placed in service during 2003 and additional depletion and depreciation related to the increased volumes from other than gob wells produced during 2003. The reductions were also offset, in part, by a $1 million increase due to the depreciation of the assets recorded in relation to the adoption of SFAS No. 143. SFAS No. 143 requires depreciation of the capitalized asset retirement cost. The depreciation of these assets is generally determined on a units-of-production basis over the life of the producing asset.

Gathering depreciation is calculated on the straight-line method. The increase represents additional depreciation related to assets placed in service in 2003.

Income Taxes


	2003			2002			Variance			Percentage Change
Earnings Before Income Taxes	$	80,011		$	42,704		$	37,307		87.4	%
Tax Expense	$	31,202		$	16,677		$	14,525		87.1	%
Effective Income Tax Rate		39.0	%		39.1	%		(0.1	)%

CNX Gas’ effective tax rate was consistent in 2003 and 2002.

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.

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 prospectus 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.

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 gas producing activities. The full-cost method allows the capitalization of all costs associated with finding oil and natural gas reserves. The successful efforts method allows only for the capitalization of costs associated with developing proven natural gas properties as well as exploration costs associated with successful exploration projects. 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 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 September 30, 2005, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $18 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.

Quantitative And Qualitative Disclosures About Market Risk

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 prospectus.

Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2004 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2004 are provided in the following table:

(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 2006 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, 2004, the fair value of these contracts was a net loss of $5.7 million (net of $3.6 million deferred tax). We continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

Hedging Volumes

As of June 30, 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
2005 Fixed Price Volumes
Hedged mcf	9,512,690	9,792,893	9,900,508	8,971,574	38,177,665
Weighted Average Hedge Price/mcf	$5.26	$4.62	$4.62	$4.59	$4.77

2006 Fixed Price Volumes
Hedged mcf	3,654,822	3,695,431	3,736,041	3,736,041	14,822,335
Weighted Average Hedge Price/mcf	$6.88	$6.88	$6.88	$6.88	$6.88

2007 Fixed Price Volumes
Hedged mcf	1,827,411	1,847,716	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 credit-worthiness 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 exposure to currency exchange-rate risks.

Liquidity and Capital Resources

We have generally satisfied our working capital requirements and funded our capital expenditures from cash generated from operations and from our principal stockholder’s (CONSOL Energy) cash management system. Under the cash management system, amounts were considered to be a capital contribution from, or a return of capital to, CONSOL Energy. 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.

Cash management for CNX Gas has been conducted by CONSOL Energy. This arrangement allowed CNX Gas to obtain funds from CONSOL Energy at any time. Prior to August 8, 2005, these amounts were considered to be a capital contribution from, or a return of capital to, CONSOL Energy. No interest has been charged or paid under this arrangement. In the twelve months ended December 31, 2004 and 2003, CNX Gas paid net cash to CONSOL Energy of $82.2 and $52.5 million, respectively and in the twelve months ended December 31, 2002, CONSOL Energy contributed net cash of $12.8 million to CNX Gas. For a brief period of time after August 8, 2005, CNX Gas continued to participate in CONSOL Energy’s cash management system under which cash generated by CNX Gas’ operations was received into CONSOL Energy’s cash accounts and CNX Gas’ payables were paid from CONSOL Energy’s cash accounts. These transactions were treated as intercompany loans.

CNX Gas 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. As a result of closing the credit agreement, our $50 million inter-company credit agreement with CONSOL Energy was terminated.

CNX Gas and its 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 its 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 again 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 again 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 its subsidiaries as guarantors of the 7.875% Notes. Based on its discussions with a number of the noteholders, 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% noteholders for the release and, consequently, we will remain guarantors of the 7.875% Notes.

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.

In order to manage the market risk exposure of volatile natural gas prices in the future, we entered into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. 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 loss of $50.3 million (net of $31.5 million of deferred tax) at September 30, 2005. The ineffective portion of the changes in the fair value of these contracts was insignificant to earnings in the three months and nine months ended September 30, 2005.

Cash Flows


	2005 Year to Date			2004 Year to Date			Change
Cash provided by operating activities	$	124,896		$	122,823		$	2,073
Cash used in investing activities	$	(72,904	)	$	(61,387	)	$	(11,517	)
Cash used in financing activities	$	(22,439	)	$	(61,438	)	$	38,999

Contractual Commitments

The following is a summary of our significant contractual obligations at September 30, 2005 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, related to these items at September 30, 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		—		—		—		—		—
Operating Lease Obligations		560		623		257		614		2,054
Purchase Obligations (a)		1,779		—		—		—		1,779
Other Long-Term Liabilities:
Gas Firm Transportation Obligation		2,131		1,638		1,434		4,268		9,471
Other Liabilities (b)		—		10		—		10,192		10,202
Well Plugging Liabilities		378		756		756		8,494		10,384
Pension		478		1,038		1,186		3,838		6,540
Postretirement Benefits Other than Pension		13		63		137		3,085		3,298

Total Contractual Obligations	$	5,339	$	4,128	$	3,770	$	30,491	$	43,728

(a)	We do not have any legally binding obligations for the purchase of goods. Purchases of goods are effected using purchase orders. We do have one agreement for the purchase of services that is enforceable and legally binding, which is included in this table.

(b)	This item represents legal contingencies reflected on the balance sheet for potential settlements of the two cases referenced in footnote 15 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 prospectus, 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. 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.

Off-Balance Sheet Transactions

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

Guarantees

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

•

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

•

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 million, and (b) Greene Energy - $3 million.

•

CONSOL Energy has an agreement with AEP Energy Services to unconditionally guarantee the full and prompt payment of all obligations, up to $15 million 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 us 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 our gas derivative hedging activity.

•

CONSOL Energy is the guarantor of the agreement dated May 26, 2004 between CNX Gas Company and Equitable Energy, LLC (in this prospectus we refer to Equitable Energy, LLC as Equitable Energy), 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 our unpaid obligations related to this agreement, up to $10 million. The guaranty shall be a continuing guaranty and CONSOL Energy has the right to terminate the guaranty by providing Equitable Energy 30 days written notice.

•

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

•

We have 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 Baltimore Gas and Electric Company related to the purchase and/or sale of natural gas. CONSOL Energy has guaranteed our unpaid obligations related to this agreement, up to $3 million. This 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, 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 thousand in the aggregate, plus reasonable costs and expenses incurred by East Tennessee, 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, CONSOL Energy shall make such payment or otherwise cause the same to be paid.

•

CONSOL Energy guaranteed the obligations of CNX Gas up to a maximum amount of approximately $53 million 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 which relate to contracts of one of our subsidiaries, we believe that once CNX Gas publishes its own financial statements in conformity with SEC rules, the counterparties to those guarantees will release CONSOL Energy from its performance obligations. The remaining guarantees will then transfer to CNX Gas. Furthermore, we do not believe this shift in guarantees will result in a material increase in cost to us.

Recent Accounting Pronouncements

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.

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.

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 is currently evaluating the impact of unvested stock options outstanding and plans to adopt the provisions of this statement January 1, 2006.

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.

BUSINESS

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. We have acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other western basins. As of March 31, 2005, we had 1,093.4 Bcfe of net proved reserves with a PV-10 value of $1,837.1 million and our standardized GAAP measure of discounted future net cash flows attributable to our proved reserves was approximately $1,157.0 million. Our proved reserves are approximately 99% CBM and 47.6% proved developed. We believe that we are the second largest gas producer in the Appalachian Basin with net sales of 48.6 Bcf for the year ended December 31, 2004. 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, 98% of our proved reserves are located in Central Appalachia where we have the right to develop approximately 296,000 net CBM acres. As of August 12, 2005, we have developed 38% of our Central Appalachian CBM acreage. In Northern Appalachia, we have the rights to develop approximately 408,000 net CBM acres of which only 7% are currently classified as developed. Our undeveloped CBM acreage contains approximately 2,431 drilling locations. In addition to our CBM activities, we participate in two joint ventures that target conventional development opportunities on approximately 423,000 gross acres throughout the Appalachian Basin. Our conventional acreage position is 99% undeveloped and contains approximately 6,434 drilling locations.

History of CNX Gas

We began extracting methane from coal seams in Virginia in 1982 as part of CONSOL Energy’s operations. Methane 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. (in this prospectus we refer to Conoco Inc. as 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. The related gas assets acquired from Occidental were sold to MCN Energy Group Inc. (in this prospectus we refer to MCN Energy Group Inc. as 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 its joint venture partner, Conoco, to consolidate its interest in Central Appalachia. This created the core of our business.

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

Areas of Operation

We operate in these principal areas of the Appalachian Basin:

•

We are also exploring for conventional natural gas on 149,820 gross acres at depths of up to 6,500 feet in Upper Devonian and Mississippian sandstones, shales and limestones. This exploration is conducted through a joint-venture, of which we own a 50% interest. As of August 12, 2005, we have participated in the drilling of 22 wells. In total, we have an inventory of approximately 1,300 conventional drilling locations on this acreage, none of which are proved undeveloped locations.

•

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 206,364 gross leasehold acres in this region. At March 31, 2005, we had 3.1 Bcfe of proved reserves in this area. As of August 12, 2005, we have 38 gross wells that are operating. In total, we have an inventory of approximately 5,134 conventional gas drilling locations on this acreage, none of which are proved undeveloped locations.

•

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 basin area from the table below, since we have not yet conducted 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	Pocohontas
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

Central Appalachia

We have the right to extract CBM in this region from approximately 296,000 net CBM acres, which contain most of the 353 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 ranges from 5 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 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 1,369 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 63% 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 35% of our gas production comes in the form of gob gas. CONSOL Energy pays for the drilling of our gob wells in most instances.

Recently, we began drilling 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 August 12, 2005, we have drilled 8 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, we believe, due 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 2% of current daily production.

Northern Appalachia

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 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 is a pay zone of thinner 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 7,443 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

Due to the significant geological differences between the Pittsburgh #8 in Northern Appalachia and the Pocahontas #3 in Central Appalachia, we have found that alternative extraction techniques are more effective than frac wells. Instead, we have developed 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 three horizontal lateral sections in the coal. Together, this combination of four wells extracts 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 9,000 to 15,000 feet of total productive wellbore and are spaced one set per 640 acre section. The vertical well, equipped with a mechanical pump, collects the water produced by the coal seam and removes it to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region.

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; Knox Energy; Kelly Oil; and Buchanan Generation. These are the companies primarily responsible for the exploration, production, transportation and sales of our gas with the exception of Buchanan Generation, which uses our gas to generate electricity from a generating facility located near our Virginia gas field. CONSOL Energy owns more than 80% of our company.

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 25% of our total gas production is attributable to mining activities, with the remainder of the gas produced using conventional techniques, reflecting our investment in additional coalbed frac wells during the past five years.

We believe the separation of our gas business from CONSOL Energy, accomplishes the following objectives:

•

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

•

Allows 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 part of our separation from CONSOL Energy, we have executed with CONSOL Energy a master separation agreement that transferred to CNX Gas these various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM and natural gas and the related surface rights. In addition, we have executed a master cooperation and safety agreement with CONSOL Energy that formalizes the relationship between CONSOL Energy and us regarding gas production associated with mining activity. This agreement is

necessary to assure that gas production activity is compatible with the safety of CONSOL Energy’s underground mines. Should CONSOL Energy reduce or liquidate its ownership of CNX Gas in the future, the terms and conditions memorialized in the master cooperation and safety agreement will remain intact, particularly as they relate to the working relationship between the companies and as to dispute resolution. We also have entered into a services agreement, an intercompany revolving credit agreement, and a tax sharing agreement with CONSOL Energy. Under the services agreement, CONSOL Energy provides us with various corporate staff services such as human resources and accounting. Under the intercompany revolving credit agreement, CONSOL Energy provided us a working capital line of credit until we obtained our new credit facility from commercial lenders. The tax sharing agreement sets forth the rights and responsibilities between CONSOL Energy and us with respect to certain tax matters.

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 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 coalbed methane. Similar circumstances exist in the production of CBM in our Northern Appalachia area, where comparable mining techniques are employed.

Coordination with Mining Activities

Approximately 25% of our current gas production is produced as a consequence of coal extraction by CONSOL Energy (not including another approximately 10% of our production that is associated with previous mining areas that continue to produce regardless of future mining activity). 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 mines. 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 drill plans that 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 have 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 our 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 without expending substantial capital on additional infrastructure.

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 wasted. Our processing plant in Virginia is one of the largest in Appalachia.

Through a joint-venture with a major eastern power generator, we own 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 coalbed methane gas 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.

We expect to create transportation alternatives through certain transportation agreements with a second interstate pipeline operator, East Tennessee, a subsidiary of Duke Energy. These agreements require the

construction by East Tennessee of an approximately 32-mile lateral pipeline to our gas field in Virginia from ETNG. Called Jewell Ridge, this proposed lateral pipeline currently is under permit review by the Federal Energy Regulatory Commission and 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 East Tennessee 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 pipeline quality 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 1,565.5 net wells, 885 miles of gathering lines and various compression stations at March 31, 2005. Our Central Appalachia operations have the right to extract gas from approximately 296,000 net CBM acres. At March 31, 2005, we had 1,068.6 Bcfe of net proved reserves in Central Appalachia, of which 46.7% is developed. Our average daily net production for the month of December 2004 in this region was 137.1 mmcf per day.

We have been developing gas production in Northern Appalachia by gathering gas currently being vented to the atmosphere by CONSOL Energy mines in the area. In this region, we operate 124 wells at March 31, 2005 and our average daily net production for the month of December 2004 was approximately 5 mmcf per day. At March 31, 2005, we had 21.7 Bcf of net proved reserves in Northern Appalachia, of which approximately 82.4% 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, our 50% portion of average daily net production for the month of December 2004 was approximately 0.5 mmcf per day. At March 31, 2005, our portion of proved net gas reserves for this area was 3.1 Bcfe, of which 100% were developed.

Drilling

The total average daily gross rate of production controlled by us during the twelve months ended December 31, 2004, was 155.7 mmcf. During the three months ended March 31, 2005 and the twelve months ended December 31, 2004, December 31, 2003 and December 31, 2002, we drilled in the aggregate 27, 235, 251 and 197 development wells, respectively, all of which were productive. The net number of wells for those periods was approximately 27, 228, 244 and 194 wells, respectively. As of August 12, 2005, we have not had any dry development wells. The following table illustrates the wells referenced above by geographic region:

Development Wells


	Three Months Ended March 31, 2005		Twelve Months Ended December 31,
	Three Months Ended March 31, 2005		2004		2003		2002
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Central Appalachia	20	20	229	222	237	237	191	191
Northern Appalachia	7	7	6	6	—	—	—	—
Tennessee	—	—	—	—	14	7	6	3

Total	27	27	235	228	251	244	197	194

During the three months ended March 31, 2005 and the twelve months ended December 31, 2004, 2003 and 2002, we drilled in the aggregate 0, 17, 52 and 34 exploratory wells, respectively. The net number of wells for those periods was 0, 12, 36 and 25 respectively. Some of the 2002 and 2003 wells are still being evaluated or are awaiting completion at June 30, 2005, however, in the aggregate they are immaterial to the financial statements as a whole. The following table illustrates the exploratory wells by geographic region:

Exploratory Wells


2004
	Gross			Net
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	—	—	—	—	—	—
Northern Appalachia	7	—	—	7	—	—
Tennessee	10	—	—	5	—	—

	17			12

2003
	Gross			Net
	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

2002
	Gross			Net
	Producing	Dry	Still Eval.	Producing	Dry	Still Eval.
Central Appalachia	15	—	—	15	—	—
Northern Appalachia	1	—	—	1	—	—
Tennessee	9	—	9	4.5	—	4.5

	25		9	20.5		4.5

Production

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


	Nine Months Ended September 30, 2005	Twelve Months Ended December 31,
	Nine Months Ended September 30, 2005	2004	2003	2002
Total Produced (mmcf)	36,060	48,556	44,459	41,298

Water produced from our Central Appalachia operations, which represents 78% of the total water produced by our gas operations, is injected into injection wells. Water from our Northern Appalachia operations is hauled to an independent treatment facility where it is treated and discharged.

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.


	Average Gas Sales Price and Lifting Cost for the
	Nine Months Ended September 30, 2005		Twelve Months Ended December 31,
	Nine Months Ended September 30, 2005		2004		2003		2002
Average Gas Sales Price Including Effects of Financial Settlements (per mcf)	$	5.56	$	5.00	$	4.14	$	3.17
Average Gas Sales Price Excluding Effects of Financial Settlements	$	5.92	$	5.41	$	4.31	$	3.17
Average Lifting Cost (per mcf)	$	0.54	$	0.50	$	0.48	$	0.40

Productive Wells and Acreage

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


	Gross	Net
Producing Wells	1,738	1,724
Proved Developed Acreage	145,791	144,261
Proved Undeveloped Acreage	38,340	38,340
Unproven Acreage	942,684	717,717

We drilled 235 development wells in the twelve months ended December 31, 2004, of which 33 wells were in process at December 31, 2004. Nearly all 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.

We currently plan to drill approximately 188 wells in the twelve-month period ending December 31, 2005. Of these wells, 150 are proposed to be conventional CBM wells drilled into coal seams not yet mined. Of the remaining wells, 36 are to be drilled into mine areas to produce gob gas and two of the projected wells are expected to be conventional gas wells. Compared to CBM wells, conventional gas wells put capital at a higher risk due to the potential for unsuccessful drilling. As such, the success rate of conventional gas wells may not reflect that of our CBM drilling program. Of these wells, 14 are proposed to be horizontal wells. Horizontal drilling techniques are designed to increase productivity and recovery rates in coal seams not conducive to vertical fracturing.

Sales

CNX Gas enters into various physical gas supply transactions with both gas marketers and end users for terms varying in length from a single day to greater than a year. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, 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. In 2004, these cash flow hedges represented 28% of our produced sales volumes at an average price of $5.10 per mcf. We intend for these transactions to cover approximately 18% of our estimated 2005 production volume. CNX Gas sold 84% of its gas sales volumes in 2004 under fixed price contracts at an average price of $4.96 per mcf compared to 90% of its gas sales volumes under fixed price contracts in 2003 at an average of $3.99 per mcf. CNX Gas has entered into fixed price gas sales contracts with various marketers representing approximately 50% of total projected 2005 production, at an average price of $4.52 per mcf in order to manage price fluctuations and achieve more predictable cash flows. We also have a gas-balancing agreement with TCO Interstate Pipeline. 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 requesting adjustments to contracted 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 imbalance amounts, for both volumes and dollars, were insignificant at December 31, 2004.

Due to the potential curtailment on portions of the shipment capacity allocated to CNX Gas as a result of increased demand for pipeline use on Columbia’s interstate gas pipeline, CNX Gas purchased firm transportation capacity on the pipeline. The first firm transportation agreement covered the May 2004 through October 2004 period. CNX Gas expects to experience potential production curtailments through spring and summer of 2005 due to capacity constrains continuing on the pipeline. In November 2004, CNX Gas engaged in an extended firm transportation agreement for use on the pipeline which covers the November 2004 through October 2006 period to offset a portion of the expected impact from the estimated curtailment. As of February 2005, purchased fixed capacity on the pipeline represents approximately 35% of our projected production for the same period. CNX Gas also participates in the short-term firm capacity markets to manage flows as market conditions dictate. In addition, in order to satisfy obligations to certain customers, we purchased gas from and sold gas to other gas suppliers, which increased our revenues and our costs.

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 14 of the notes to the consolidated annual financial statements included in the prospectus.

Distribution

Our gas operations in Central Appalachia have built separate gathering systems in their gas fields to deliver gas to market. 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 systems. The first gathering system is a 50-mile, 16-inch gathering system that is capable of transporting 100 mmcf of gas per day. This gathering system has processing and compression facilities and connects with a Columbia pipeline located in Mingo County, West Virginia. The second gathering system is a 30-mile, 20-inch gathering system capable of transporting 150 mmcf of gas per day. This gathering system also connects with a Columbia gathering system in Wyoming County, West Virginia.

Transportation

We market our gas to third party gas marketers. Given the present size of our company, we believe that this is the most cost-effective way to handle the sale of our gas. In Central Appalachia, we operate a large gathering system to move our gas from producing wells to third-party interstate transporters. The gathering system has a capacity of 250 mmcf compared with our 2004 annual average daily gross production of 156 mmcf. This excess capacity is vital to our plans to continue to grow our production volumes in Central Appalachia.

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 KA-20 line that transports all of our Central Appalachia gas to market. The growth of production in the Appalachian basin, expansion of Cove Point downstream on the pipeline and summer season maintenance have resulted in a bottleneck issue on the Columbia pipeline system. We purchased firm transportation on the Columbia Transmission pipeline effective November 2004 through April 30, 2015. We expect similar curtailments on KA-20 in 2005 and 2006, primarily during April-October of 2005 and April-May of 2006. We have forecasted 1.1 Bcf of production of curtailment in 2005 financial forecasts and 2.4 Bcf in 2006.

Our solution to the bottleneck issue on Columbia’s pipeline is to gain access to Duke Energy’s ETNG pipeline, which is south of our Central Appalachia operations. Duke Energy is in the process of seeking

regulatory approval for the construction of a 32-mile interstate gas pipeline, called Jewell Ridge pipeline, that will transport gas from our Central Appalachia operations to the ETNG gas pipeline. Jewell Ridge pipeline is expected to be in service in the second half of 2006 and will provide us with an alternate transportation route to the Northeast markets we currently serve as well as access to markets in the Mid-Atlantic region.

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 recovered 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 a 1/8 royalty ownership. 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 undeveloped reserves are defined by the SEC Rule 4.10(a) of Regulation S-X.


	Net Reserves (mmcfe)
	As of March 31,		As of December 31,
	2005		2004		2003		2002
	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates	Consolidated Operations	Equity Affiliates
Estimated proved developed reserves	515,801	4,435	395,152	1,489	352,935	843	329,687	559
Estimated proved undeveloped reserves	573,170	—	647,251	896	649,865	738	630,259	—

Total estimated proved developed and undeveloped reserves	1,088,971	4,435	1,042,403	2,385	1,002,800	1,581	959,946	559

Discounted Future Net Cash Flows

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


	Discounted Future Net Cash Flows ($ in thousands)
	As of March 31, 2005		As of December 31,
	As of March 31, 2005		2004		2003		2002
Future net cash flows (net of income tax)	$	3,099,411	$	2,872,571	$	2,708,797	$	2,037,696
Total standardized measure of discounted future net cash flows (net of income tax)	$	1,055,405	$	1,029,538	$	1,011,186	$	735,181
Total standardized measure of pre-tax discounted future net cash flows	$	1,837,127	$	1,655,232	$	1,556,866	$	1,089,900

Competition

CNX Gas operations primarily compete regionally in the northeastern United States. Competition throughout the country is regionalized. CNX Gas believes that the gas market is highly fragmented and not dominated by any single producer. CNX Gas believes that several of its competitors have devoted far greater resources than it has to gas exploration and development. CNX Gas believes that competition within its market is based primarily on price 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 Kelly Oil). 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 (in this prospectus we refer to New River Energy, LLC as New River Energy). The operating agreement of Knox Energy contemplates a management agreement (discussed below) by which CNX Gas Company LLC manages the operations of Knox Energy.

Knox Energy is engaged in certain drilling operations in Tennessee, covering approximately 207,884 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. (in this prospectus we refer to Atlas America, Inc. as Atlas). In September 2004, Knox Energy entered into a drilling and operating agreement with Atlas which relates to certain natural gas and oil wells located in Anderson, Campbell, 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. All gas and oil 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, LLC, Duke Energy Trading and Marketing, L.L.C. and Citizens Gas Utility District, to transport all of the gas from their facilities.

Buchanan Generation LLC

This Virginia limited liability company is owned 50% by us 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 facility.

This facility operates on gas produced by CNX Gas’ Central Appalachia operations. The generation facility, known as the “Peaker Power Plant,” 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.

Below is an organizational chart of the company:

LOGO

Employee and Labor Relations

As of September 20, 2005, CNX Gas had 124 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 oil 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. In addition, the utility industry is subject to extensive regulation regarding the environmental impact of its power generation activities and manufacturers are subject to clean air regulation, both of which could affect demand for our gas. 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 their operations significantly or incur substantial costs.

Environmental Regulation of Gas Operations

Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay 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 made capital expenditures for environmental control facilities of approximately $253 thousand for the twelve months ended December 31, 2002. CNX Gas had no other environmental control facility expenditures in 2003 or 2004. CNX Gas expects to have no capital expenditures for 2005 for environmental control facilities. 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 its 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 Comprehensive Environmental Response, Compensation and Liability Act (Superfund);

•

the Resource Conservation and Recovery Act; and

•

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

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

These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained all required permits under federal and state environmental laws for its 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 have been named as a potentially responsible party at Superfund sites in the past. 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;

(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, 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. Historically, 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 resources. Although CONSOL Energy generally attempts to obtain ownership or leasehold rights to CBM and/or conventional gas related to its coal resources, 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 prospectus.

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 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 August 12, 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.

Pennsylvania and West Virginia have not been the focus of our developmental activities. 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.

Legal Proceedings

CNX Gas is 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. In the opinion of management, the ultimate liabilities resulting from such pending lawsuits and claims will not materially affect the financial position, results of operations or cash flows of CNX Gas.

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 paid applicable license taxes based on the delivered price of the product. The audit is ongoing with no resolution being proposed by Buchanan County as of August 12, 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. CL05-) 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 coalbed methane 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.

CDX Gas, LLC has alleged that certain of our vertical to horizontal coalbed methane 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 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. This litigation is in a very early stage and we cannot predict the outcome of the litigation.

New 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, the $50 million intercompany credit agreement with CONSOL Energy automatically 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 included our recent 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;

•

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.

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 (x) our outstanding indebtedness (less cash on hand) is less than or equal to our consolidated earnings before interest, taxes, depreciation and amortization, (y) 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 (z) no default or potential default exists.

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.

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.

MANAGEMENT

The following is a list of CNX Gas’s executive officers and directors, their ages as of December 15, 2005 and their positions and offices held with CNX Gas.


Name	Age	Position
Nicholas J. DeIuliis	37	Chief Executive Officer, President 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	46	Senior Vice President, Secretary and General Counsel
J. Brett Harvey	55	Director
James E. Altmeyer, Sr.	67	Director
Philip W. Baxter	57	Chairman of the Board
Raj K. Gupta	63	Director
John R. Pipski	58	Director
William J. Lyons	57	Director

Nicholas J. DeIuliis has been Senior Vice President—Strategic Planning of CONSOL Energy since November 1, 2004. 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, a member of the Pennsylvania Bar and a member of the Pennsylvania and American Bar Associations. He has been a director and Chief Executive Officer and President of CNX Gas since its formation on June 30, 2005. He resigned from his position with CONSOL Energy as of August 8, 2005. 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 has been Executive Vice President—Gas Operations, Land Resources and Engineering Services of CONSOL Energy since April 1, 1992. 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 became CNX Gas’ Chief Operating Officer on June 30, 2005 (and an Executive Vice President on December 5, 2005) and resigned from his position with CONSOL Energy as of August 8, 2005. 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 has been Vice President—Tax of CONSOL Energy since April 11, 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 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 became CNX Gas’ Chief Financial Officer on June 30, 2005 (and a Senior Vice President on December 5, 2005) and resigned from his position with CONSOL Energy as of August 8, 2005. Mr. Bench received his bachelor’s degree in accounting from Indiana University of Pennsylvania and a master’s in taxation from Robert Morris University.

Stephen W. Johnson 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.

J. Brett Harvey has been President and Chief Executive Officer and a Director of CONSOL Energy since January 1998. He has been a director of CNX Gas since June 30, 2005, the date of its formation. Prior to joining CONSOL Energy, Mr. Harvey served as the President and Chief Executive Officer of PacifiCorp Energy Inc., a subsidiary of PacifiCorp, from March 1995 until January 1998. Mr. Harvey also was President and Chief Executive Officer of Interwest Mining Company from January 1993 until January 1998 and Vice President of PacifiCorp Fuels from November 1994 until January 1998. Mr. Harvey is a member of the National Mining Association, World Coal Institute, IEA Coal Industry Advisory Board, Waterways Council, Inc., member of the board of directors of the Bituminous Coal Operators’ Association, member of the executive committee and the board of the Center for Energy & Economic Development, member of the CEO Group of the Coal-Based Generation Stakeholders, Executive Advisory Board of the Virginia Coalfield Development Authority, National Coal Council, The Conservation Fund Corporate Counsel and chairman of the Greater Pittsburgh Council of Boy Scouts of America. He received a bachelor’s degree in Mining Engineering from the University of Utah.

James E. Altmeyer, Sr., has been a director of CONSOL Energy since November 2003 and a director of CNX Gas since June 30, 2005, the date of its formation. He currently serves as a member of the Audit Committee and Compensation Committee of CONSOL Energy. Mr. Altmeyer has been president and chief executive officer of Altmeyer Funeral Homes, Inc. of West Virginia, Ohio, and Virginia since 1972. He also has been president of Altmeyer Realty, a real estate holding company, and of Martin-Steadfast Insurance Company since 1972. Since 1987, Mr. Altmeyer has served on the board of directors of Wesbanco, a multi-state bank holding company with offices in Pennsylvania, West Virginia and Ohio, and currently serves on its audit committee. Mr. Altmeyer also serves as a member of the executive committee of the board of directors of Wheeling Hospital; chairman of the Fire Department Civil Service Commission of Wheeling; president of the American Legion Home Corporation; vice chairman of the Chambers Foundation and, in April 2003, he was appointed to the U.S. Small Business Administration Advisory Council for Veterans Business Affairs. Mr. Altmeyer is a graduate of the U.S. Military Academy, West Point, New York.

Philip W. Baxter has been a director of CONSOL Energy since August 1999 and the Chairman of the Board of CNX Gas since June 30, 2005, the date of its formation. Mr. Baxter has served as Chairman of the audit committee and as a member of the finance committee of CONSOL Energy. On August 2, 2005, Mr. Baxter resigned his position as a member of CONSOL Energy’s board of directors. Mr. Baxter has been the president of Stan Johnson Company, a nationally recognized leader in commercial real estate brokerage specializing in single-tenant properties, since 2002. Mr. Baxter was chief financial officer and executive vice president of the Tulsa-based energy conglomerate, Mapco Inc., until March 1998 when it merged with The Williams Company. During his 18-year career at Mapco, Mr. Baxter held a number of officer level positions including chief information officer and senior vice president of Strategic Planning. Prior to his career at Mapco, he held a number of financial positions with Williams Energy Company, a subsidiary of The Williams Company. Mr. Baxter received a bachelor’s degree in Business Administration from the University of Oklahoma and is a 1992 graduate of the Darden Executive Program of the University of Virginia.

Raj K. Gupta has been a director of CONSOL Energy since February 2004 and a director of CNX Gas since June 30, 2005, the date of its formation. He currently serves as a member of the audit committee and the finance committee of CONSOL Energy. Currently an independent management consultant, from 1965 until his retirement in 2000, Mr. Gupta held various management positions with Phillips Petroleum Company, an international integrated oil and gas company now part of ConocoPhillips, including vice president of strategic planning, managing the company’s strategic planning, growth and globalization efforts in South America, China, the Middle East and the former Soviet Union. From 2000 to December 2004, he served on the board of directors of Yukos Oil Company, Moscow, Russia, chaired its compensation committee and was a member of its audit and

finance committees. Since 2000, Mr. Gupta has been a member of the Advisory Council of the Industrial, Manufacturing and Systems Engineering at Kansas State University. He also serves on the advisory board of Preng & Associates in Houston. Mr. Gupta earned a master’s degree in Industrial Engineering and Management Science from Kansas State University and a Bachelor of Science degree in Mechanical Engineering with Honors from Birla Engineering College in India.

John R. Pipski has been a director of CNX Gas Corporation since August 15, 2005. Since 2001, Mr. Pipski has provided financial and tax accounting services to business clients, through his own firm. Prior to that endeavor, from 1970 to 2001, he held various positions at the international accounting firm of Ernst & Young, LLP. For eighteen years, Mr. Pipski was a Tax Partner specializing in corporate taxation, mergers and acquisitions and tax accounting issues in the coal and manufacturing industries. In addition, he held various positions within the Tax and Audit Departments of that firm. Mr. Pipski has served as a Board Member and Treasurer of The Ronald McDonald House Charities of Pittsburgh. Mr. Pipski is a certified public accountant and earned bachelors and masters degrees in financial administration from Michigan State University.

William J. Lyons has been a director of CNX Gas since October 17, 2005. Mr. Lyons has been Chief Financial Officer of CONSOL Energy since February 1, 2001. From January 1, 1995 to February 1, 2001, Mr. Lyons held the position of Vice President-Controller for CONSOL Energy. Mr. Lyons joined CONSOL Energy in 1976.

Board of Directors

Our board of directors currently consists of seven (7) directors. We are not currently required to comply with the corporate governance rules of any stock exchange or NASDAQ and, as a private company, we are currently subject to very few provisions of the Sarbanes-Oxley Act of 2002 and related SEC rules (collectively, “Sarbanes-Oxley”). However, upon the effectiveness of this registration statement, we will become subject to all of the provisions of Sarbanes-Oxley and, if our common stock becomes so listed, the rules of the applicable stock exchange or NASDAQ. Because our principal stockholder, CONSOL Energy, continues to control more than 50% of the voting power of our common stock, we believe that we will meet the criteria for being a “controlled” company under stock exchange or NASDAQ rules. If this exception applies to us, we will be required to comply with the requirements that govern controlled companies, including the audit committee requirements. If we do not qualify or no longer qualify as a controlled company, the rules of the applicable stock exchange or NASDAQ will require that a majority of our board consists of independent directors and certain other provisions of those organizations’ governance standards would apply to us.

Committees of the Board

The board of directors has four standing Committees: Audit, Compensation, Nominating and Corporate Governance, and Finance. The Audit committees is currently comprised solely of non-employee, independent directors in accordance with applicable listing standards of both the NYSE and NASDAQ. As stated above, we intend to comply with the controlled company rules of the applicable stock exchange or NASDAQ with respect to our Compensation and Nominating and Corporate Governance Committees.

Audit Committee. The Audit Committee is responsible for providing assistance to the board of directors in fulfilling its legal and fiduciary obligations with respect to matters involving the accounting, financial reporting, internal control and compliance functions of CNX Gas and its subsidiaries. The Audit Committee, which currently consists of three directors, employs an independent registered public accounting firm, subject to shareholder ratification, to audit the financial statements of CNX Gas and its subsidiaries and performs other assigned duties. Further, the Audit Committee provides general oversight with respect to the accounting principles employed in financial reporting and the adequacy of CNX Gas’s internal controls. In discharging its responsibilities, the Audit Committee is entitled to rely on the reports, findings and representations of its auditors, legal counsel, and responsible officers. The current members of the Audit Committee are Messrs. Pipski (Chair), Altmeyer and Gupta with Mr. Baxter serving in an ex-officio role.

Compensation Committee. The Compensation Committee, which currently consists of two directors, is responsible for establishing executive compensation policies consistent with corporate objectives and shareholder

interests. The Compensation Committee recommends to the board of directors levels of compensation for the Chief Executive Officer, President and other executive officers, including salary, variable compensation and long-term incentives. The Compensation Committee also takes action regarding incentive and equity-based plans and programs, any appropriate employment contracts, special retirement benefits, severance, change in control arrangements, or similar plans and is responsible for their oversight or administration. The current members of the Compensation Committee are Messrs. Altmeyer (Chair) and Harvey with Mr. Baxter serving in an ex-officio role.

Nominating and Corporate Governance Committee. The Nominating and Corporate Governance Committee, which currently consists of two directors, is responsible for recommending to the board of directors nominees for election as directors at the Annual Meeting of Shareholders or appointment as directors in the event of any vacancy, generally monitoring CNX Gas’s corporate governance system and performing any other functions or duties deemed appropriate by the board of directors. The Nominating and Corporate Governance Committee also oversees the annual evaluation of the board and the board committees and delivers reports to the board setting forth the results of such evaluations. The current members of the Nominating and Corporate Governance Committee are Messrs. Harvey (Chair) and Altmeyer with Mr. Baxter serving in an ex-officio role.

Finance Committee. The Finance Committee, which currently consists of three directors, is responsible for monitoring and providing advice and counsel to the board of directors and the management of CNX Gas regarding its asset mix, potential mergers and acquisitions, capital structure and policies, financial position and policies, financing activities, financial risk management policies and activities, dividend policies and the ERISA-qualified, funded plans sponsored by CNX Gas. The current members of the Finance Committee are Messrs. Gupta (Chair), Lyons and Pipski with Mr. Baxter serving in an ex-officio role.

Compensation of Directors

CNX Gas was formed on June 30, 2005. Prior to August 1, 2005, CNX Gas was operated as a division of CONSOL Energy and did not have a separate board of directors, compensation committee or other board committees performing similar functions. These functions were performed by the board of directors, the compensation committee and the executive officers of CONSOL Energy.

Our board of directors is newly created. We intend that any members of the board of directors who are employees of CONSOL Energy, CNX Gas or any of their subsidiaries will not be compensated by us for service on the board of directors or on any of its committees. Other members of the board of directors will receive an annual board membership fee of $25,000, with the exception of the non-executive chairman of our board of directors who will receive an annual board membership fee of $80,000. The members of the board of directors will also receive an attendance fee of $1,500 for each meeting of the board of directors; an attendance fee of $1,000 for each audit committee meeting of the board of directors and, if chairman of the audit committee, a $5,000 annual fee, an attendance fee of $1,000 for each meeting of the compensation committee or nominating or corporate governance committee of the board of directors upon which they serve and, if chairman of either of these committees, an annual fee of $3,000; and, in accordance with the terms of CNX Gas’s Equity Incentive Plan, an initial restricted stock unit grant for 60,000 shares, in the case of the non-executive chairman of the board of directors, and an initial restricted stock unit grant for 10,000 shares, in the case of the other directors. In connection with other actions taken by the CNX Gas board of directors on August 1, 2005, the CNX Gas board of directors determined that beginning in 2006 CNX Gas intends to make to Mr. Baxter and each of the other CNX Gas directors that are not employees of CNX Gas or CONSOL Energy annual grants with aggregate dollar values of $200,000 and $50,000, respectively, payable 50% in the form of CNX Gas stock options and 50% in the form of CNX Gas restricted stock units. See “Management—CNX Gas Equity Incentive Plan.”

Compensation of Executive Officers

The following table sets forth information concerning the annual and long-term compensation for services rendered in all capacities to CONSOL Energy and its subsidiaries for the years noted of the individuals who will

serve as our chief executive officer and our other named executive officers. The compensation described in this table was paid by CONSOL Energy or an affiliate of CONSOL Energy. The services rendered to CONSOL Energy were, in some cases, in capacities not equivalent to those to be provided to us and this table does not reflect the compensation to be paid to executive officers in the future.

Summary Compensation Table


	Annual Compensation									Long Term Compensation
	Annual Compensation									Awards				Payouts
Principal Position	Year	Salary		Bonus			Other Annual Compensation(4)			Restricted Stock Award(6)			# Securities Options/SARs(8)	LTIP Payouts	All Other Compensation(9)
Nicholas J. DeIuliis	2004	$	232,713	$	300,000	(1)	$	5,915	(5)	$	342,705	(7)	11,780	—	$	12,050
Chief Executive Officer and President

Ronald E. Smith	2004	$	358,322	$	460,000	(1)	$	2,885	(5)	$	567,891	(7)	39,875	—	$	12,300
Chief Operating Officer	2003 2002		298,411 286,530		— 178,694	(2)(3)		— 54	(5)		—		65,100 55,000	— $30,940		11,769 12,000

Gary J. Bench Chief Financial Officer	2004	$	124,267	$	56,498	(1)		—		$	42,938	(7)	4,225	—	$	7,456

(1)	Bonuses for 2004 represent amounts paid in 2005, but earned in 2004.

(2)	Bonus for 2002 represent amounts paid in 2003, but earned in 2002.

(3)	Represents additional compensation awards granted by the CONSOL Energy board of directors not falling under CONSOL Energy’s Short-Term Plan.

(4)	Except as indicated, other compensation in the form of perquisites and other personal benefits has been omitted because it accounted for the lesser of $50,000 or 10% of the total salary and bonus for each of CNX Gas’ named executive officers for that year.

(5)	For Mr. DeIuliis includes income tax reimbursement for financial planning assistance. For Mr. Smith includes income tax reimbursement for financial planning in 2005 and income tax reimbursement for air travel in 2002.

(6)

The values expressed in the column were determined by multiplying the closing sales price of CONSOL Energy common stock on the date of grant by the number of restricted stock units granted. At the close of business on December 31, 2004, the fair market value of the non-vested restricted stock units held by each named executive officer was as follows: Mr. DeIuliis: 11,134 units valued at $457,051; Mr. Smith: 18,450 units valued at $757,373; and Mr. Bench: 1,395 units valued at $57,265. CONSOL Energy paid dividends on the restricted stock awards, which amounts are included in the column.

(7)

Consists of grants of 8,095, 8,095 and 323 shares of unvested restricted stock units of CONSOL Energy vesting ratably over three years given as a special recognition award to Messrs. DeIuliis, Smith and Bench, respectively, each valued at the market price as of the date of grant; and grants of 3,039, 10,355 and 1,072 shares of unvested restricted stock units vesting ratably over four years to Messrs. DeIuliis, Smith and Bench, respectively, each valued at the market price as of the date of grant.

(8)	This column represents options to purchase shares of CONSOL Energy common stock.

(9)	Represents matching contributions to CONSOL Energy’s 401(k) Plan.

We have initially set Messrs. DeIuliis, Smith, Bench and Johnson annual base salaries at $400,000, $380,000, $180,000 and $180,000 respectively. Additionally, one-time bonus payments in the following amounts were made to Messrs. DeIuliis, Smith and Bench, respectively, $250,000, $150,000 and $80,000. Each of Messrs. DeIuliis, Smith, Bench and Johnson will also be eligible to receive annual short-term incentive compensation

currently targeted at 100%, 75%, 45% and 45%, respectively, of their annual base salary as of the year end, but which incentive compensation in each case, could amount to a maximum of 300% of their respective full-year base salaries. The 2005 short-term incentive compensation payments would be paid by CNX Gas and are expected to be based on performance criteria relating to CONSOL Energy (except for Mr. Johnson who was not previously employed by CONSOL Energy) and CNX Gas and the executive’s performance during his service with each entity in 2005. Thereafter, short-term incentive compensation payments are expected to be based upon criteria relating to CNX Gas and the executive’s performance with CNX Gas. In addition, pursuant to the terms of the CNX Gas Equity Incentive Plan, Messrs. DeIuliis, Smith, Bench and Johnson received a one-time grant of CNX Gas stock options exercisable for 281,481, 266,667, 79,074 and 22,222 shares of CNX Gas common stock, respectively, and, commencing in 2006, annual grants with an aggregate dollar value of $750,000, $630,000, $195,000 and $190,000, respectively, payable 75% in the form of CNX Gas stock options and 25% in the form of CNX Gas restricted stock units. Mr. Johnson also received an initial grant of 21,112 stock options and 2,969 restricted stock units. See “Management—CNX Gas Equity Incentive Plan.”

CONSOL Energy Stock Option Grants

The following table sets forth the individual grants of stock options exercisable for common stock of CONSOL Energy made to Messrs. DeIuliis, Smith and Bench from CONSOL Energy during the twelve months ended December 31, 2004. There were no stock appreciation rights granted during the twelve months ended December 31, 2004.

Option/SAR Grants in Last Fiscal Year


	Number of Securities Underlying Options/SARs Granted	% of Total Options/SARs Granted to Employees In Fiscal Year	Exercise or Base Price ($/Sh)	Expiration Date	Potential Realizable Value at Assumed Annual Rates of Stock Price Appreciation for Option Term $
Name	Number of Securities Underlying Options/SARs Granted	% of Total Options/SARs Granted to Employees In Fiscal Year	Exercise or Base Price ($/Sh)	Expiration Date	5%	10%
Nicholas J. DeIuliis	11,780	1.48	30.78	2014	228,030	577,873
Ronald E. Smith	39,875	5.01	30.78	2014	771,875	1,956,084
Gary J. Bench	4,225	0.53	30.78	2014	81,785	207,259

The stock options granted to these executive officers terminate ten years after the date on which they were granted. The stock options will vest 25% per year, beginning one year after the grant date. The vesting of the options will accelerate upon a change of control of CONSOL Energy. A termination of employment will have the following effects on stock options granted under the CONSOL Energy equity incentive plan:

•

if the employee is terminated for cause or has breached any of the restrictive covenants set forth in the applicable stock option award agreement, such as its non-compete provisions, the options (whether vested or unvested) will be deemed cancelled and forfeited in their entirety;

•

if the employee is terminated without cause (except for a reduction in force) or does so voluntarily; the unvested portion of the options will be deemed cancelled and forfeited and the vested portion, if any, will remain exercisable for a period of 90 days following such termination of employment;

•

if the employee’s employment is terminated as a result of death, the options will vest in full and will remain exercisable for the lesser of 3 years or until the expiration date of the options;

•

if the employee terminates employment by retiring, the nature of the retirement affects the status of the options under the CONSOL Energy equity incentive plan thereafter.

On May 3, 2005, the CONSOL Energy compensation committee granted Messrs. DeIuliis, Smith and Bench options to purchase 5,480, 18,662, and 1,936 shares of its common stock at an exercise price of $45.50 and 2,033, 6,924, and 719 restricted stock units, respectively.

Aggregated Option/SAR Exercises in Last Fiscal Year

and Fiscal Year-End Option/SAR Values

The following table sets forth for each of the named executive officers the number of shares subject to both exercisable and unexercisable stock options in respect of CONSOL Energy’s common shares, as well as the value of unexercisable in-the-money options, as of the end of December 31, 2004, based on the closing price of CONSOL Energy’s common stock on that date. No CNX Gas executive officer held stock appreciation rights which became exercisable during the year ended December 31, 2004.


				Number of Securities Underlying Unexercised Options/SARs at Fiscal Year End (#)	Value of Unexercised in- the-Money Options/SARs at Fiscal Year End ($)
Name	Shares Acquired on Exercise(#)	Value Realized($)		Exercisable/ Unexercisable(1)	Exercisable/ Unexercisable(2)
Nicholas J. DeIuliis	—		—	20,075/35,405	$	430,942/686,871
Ronald E. Smith	—		—	172,200/129,875		3,802,997/2,526,454
Gary J. Bench	2,162	$	38,482	8,350/16,601		147,531/334,119

(1)	As of December 31, 2004.

(2)	Calculated on the basis of the closing sales price of $41.05 per share on December 31, 2004, less the exercise price per share.

Retirement Benefits

Pension benefits for salaried employees under CONSOL Energy’s Retirement Plan are based on an employee’s years of service and average monthly pay during the employee’s three highest-paid years. “Average monthly pay” for this purpose includes regular compensation and 100% of annual variable compensation payments, but excludes other bonuses and compensation in excess of limits imposed by the Internal Revenue Code of 1986, as amended (the “Code”). The Code limits the amount of annual benefits which may be payable from the pension trust. Retirement benefits provided under the pension plan in excess of these limitations are paid from CNX Gas’s general revenues under separate, nonfunded pension restoration plans. Salaried employees of CNX Gas will not continue to participate in CONSOL Energy’s Retirement Plan. CNX Gas intends to adopt its own benefit plans, including a retirement plan, but has not yet adopted any benefit plans. Management anticipates that a retirement plan will be adopted which includes some level of a defined pension benefit as well as a defined contribution feature.

Pension Plan Table


Years of Service
Remuneration	15	20	25	30	35(1)
$90,000	$21,600	$28,800	$35,500	$36,700	$36,700
$145,000	$34,800	$46,400	$57,200	$58,900	$58,900
$200,000	$48,000	$64,000	$79,000	$81,100	$81,100
$255,000	$61,200	$81,500	$100,700	$103,300	$103,300
$310,000	$74,400	$99,100	$122,400	$125,500	$125,500
$365,000	$87,600	$116,700	$144,100	$147,700	$147,700
$420,000	$100,800	$134,300	$165,800	$169,900	$169,900
$530,000	$127,200	$169,500	$209,200	$214,300	$214,300
$640,000	$153,600	$204,600	$252,600	$258,600	$258,600
$750,000	$180,000	$239,800	$296,100	$303,000	$303,000

(1)

Prior to November 1, 1975, CONSOL Energy’s Pension and Retirement Plan did not provide benefits to employees who had not then attained 30 years of age. Consequently, as of the date hereof, the level of benefits for employees with 35 years of service does not differ from the level available to employees with 30 years of service.

The foregoing table illustrates the straight life annuity amounts payable under the Pension and Retirement Plan and pension restoration plans to CONSOL Energy employees retiring at age 65 in 2003. Amounts shown above are subject to deduction for Social Security payments. The current years of service credited for retirement benefits for the CNX named executive officers are as follows: 15 years for Mr. DeIuliis, 29 years for Mr. Smith and 20 years for Mr. Bench.

Compensation Committee Interlocks and Insider Participation

At the time our executive officers’ compensation was set we did not have a compensation committee and therefore our board of directors participated in deliberations concerning our named executive officers’ compensation. J. Brett Harvey, who serves on our board of directors, is President and Chief Executive Officer of CONSOL Energy, our principal stockholder. Nicholas J. DeIuliis, who serves on our board of directors was, until August 8, 2005, Senior Vice President—Strategic Planning of CONSOL Energy, our principal stockholder.

CNX Gas engages in, and plans to continue to engage in, business transactions with CONSOL Energy and its affiliates. All of the matters set forth under “Relationship with CONSOL Energy and Certain Transactions with Affiliates and Management” are herein incorporated by reference to this portion of the prospectus.

Employment Agreements

Neither Messrs. DeIuliis, Smith, Bench nor Johnson has an employment agreement with CNX Gas but Messrs. Smith, Bench and Johnson have been provided an offer letter setting forth the compensation arrangements with CNX Gas described in this prospectus.

CNX Gas Change in Control Severance Agreements

CNX Gas has entered into change in control severance agreements with each of Messrs. DeIuliis, Smith, Bench and Johnson (each an “Executive” and, collectively, the “Executives”), which provide that, subject to CONSOL Energy’s reemployment rights described below with respect to Messrs. DeIuliis and Bench, if the Executive is terminated:

(1) after, or in connection with, a Change in Control (as defined below) for any reason other than cause, death or disability or if, within the two-year period after a Change in Control, he is constructively terminated, which includes: (a) an adverse change in his position; (b) a reduction in annual base salary or target bonus or a material reduction in employee benefits; (c) a material change in circumstances, including a material change in the scope of CNX Gas’ business, as determined by the Executive, which has rendered the Executive unable to carry out his duties; (d) the liquidation, dissolution, merger, consolidation or reorganization of CNX Gas or transfer of all or substantially all of CNX Gas’s business or assets; or (e) the relocation of the Executive’s principal work location to a location that increases his normal commute by 50 miles or more or that requires travel increases by an unreasonable amount; or

(2) other than for cause, death or disability, not more than three months prior to the date on which a Change in Control occurs or at the request of a third party who initiates a Change in Control and upon the execution of a release, the Executive will receive:

(a) a lump sum cash payment equal to (x) (i) a multiple of the Executive’s base pay, plus (ii) a multiple of the Executive’s incentive pay (the multiple, in each case, for Mr. DeIuliis is 2.5, and for Messrs. Smith, Bench and Johnson, 2.0); and (y) a pro rated payment of his incentive pay for the year in which his termination of employment occurs; (b) for 24 months (30 months in the case of Mr. DeIuliis), the continuation of medical and dental coverage (or a lump sum payment in lieu of continuation at the election of CNX Gas); (c) if the Executive would have been eligible for post-retirement medical and dental coverage had he retired from employment during the period of 24 months (30 months in the case of Mr. DeIuliis) following termination of employment but

is not so eligible because of the termination, then at the end of the 24 month (30 months in the case of Mr. DeIuliis) period described in (b), CNX Gas will provide continued medical and dental coverage comparable to that which would have been available to him under the CNX Gas post-retirement medical and dental benefits program for as long as such coverage would have been available under that program (or a lump sum cash payment in lieu of continuation at the election of CNX Gas); (d) a lump cash payment equal to the amount that the Executive would have received under CNX Gas’ 401(k) plan as a match, if he was eligible to participate in CNX Gas’ 401(k) plan for 24 months (30 months in the case of Mr. DeIuliis) after his termination date, and he contributed the maximum amount to the plan for the match; (e) a lump cash payment equal to the difference between the present value of his accrued pension benefits at his termination date under CNX Gas’ qualified defined benefit plan and (if eligible) its pension restoration plan (together, the “pension plans”) and the present value of the accrued pension benefits to which the Executive would have been entitled under the pension plans if he had continued participation in those plans for 24 months (30 months in the case of Mr. DeIuliis) after his termination date; (f) a lump sum cash payment of $25,000 in order to cover the cost of outplacement assistance services and other expenses associated with seeking other employment; and (g) any amounts earned, accrued or owing but not yet paid as of his termination date, payable in a lump sum, and any benefits accrued or earned in accordance with the terms of any applicable benefit plans and programs of CNX Gas.

In addition upon a Change in Control, all equity awards held by the Executive in CNX Gas and CONSOL Energy will become fully vested and/or exercisable on the date the Change in Control occurs and all stock options or stock appreciation rights will remain exercisable for the period set forth in the applicable award agreement.

A “Change in Control” means:

(1) the acquisition by any individual, entity or group (within the meaning of section 13(d)(3) or 14(d)(2) of the Exchange Act) (a “Person”) of beneficial ownership (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of more than 25% of the combined voting power of the then outstanding voting stock of CNX Gas, other than any such acquisition:

(a)

directly from CNX Gas that is approved by the Incumbent Board (as defined below);

(b)

by CNX Gas, CONSOL Energy or any of their respective subsidiaries, by any employee benefit plan (or related trust) sponsored or maintained by CNX Gas, CONSOL Energy or any of their respective subsidiaries or affiliates;

(c)

by an underwriter in connection with a public offering; or

(d)

in a business combination (as defined below) that complies with 3 (a), (b) and (c) below; or

(2) other than at a time when CONSOL Energy and/or its subsidiaries beneficially own more than 50% of the total voting stock of CNX Gas, individuals who constitute the board of directors (the “Incumbent Board”) (or whose election was approved by two-thirds of the Incumbent Board, other than any director elected as a result of an actual or threatened election contest) cease for any reason to constitute at least a majority of the board of directors; or

(3) consummation of a reorganization, merger or consolidation of CNX Gas or a direct or indirect wholly owned subsidiary of CNX Gas, a sale or other disposition of all or substantially all of the assets of CNX Gas, or certain other transactions involving CNX Gas (each, a “business combination”), unless, in each case, immediately following such business combination:

(a)

all or substantially all of the individuals and entities who were the beneficial owners of voting stock of CNX Gas immediately prior to such business combination beneficially own, directly or indirectly, more than 50% of the combined voting power of the then outstanding shares of voting stock of the entity resulting from such business combination or any direct or indirect parent corporation of such entity;

(b)

no person other than CNX Gas and/or CONSOL Energy and/or their respective subsidiaries beneficially owns 25% of more of the combined voting power of the then outstanding shares of voting stock of the entity resulting from such business combination or any direct or indirect parent corporation of such entity; and

(c)

other than at a time when CONSOL Energy and/or its subsidiaries beneficially own more than 50% of the total voting stock of CNX Gas, at least a majority of the members of the board of directors of the entity resulting from such business combination or any direct or indirect parent corporation thereof were members of the Incumbent Board at the time of the execution of the initial agreement or of the action of the board providing for such business combination;

(4) approval by the stockholders of CNX Gas of a complete liquidation or distribution of CNX Gas, except pursuant to certain business combinations; or

(5) other than at a time when CONSOL Energy and/or its subsidiaries beneficially own less than 50% of the total voting stock of CNX Gas, a Change in Control of CONSOL Energy (as defined below under “—CONSOL Energy Change in Control Severance Agreements”).

The change in control severance agreements also provide that in the event that Mr. DeIuliis’s or Mr. Bench’s employment is terminated in connection with a Change in Control for any reason other than death, disability or cause or if such Executive is constructively terminated as described above (other than in the event of a Change in Control of CONSOL Energy), CONSOL Energy may, in its sole discretion, elect on or before the 30th day following such Executive’s termination date to reemploy the Executive on a full time basis in a salaried position. In the event CONSOL Energy elects to reemploy the Executive, the Executive shall be entitled to receive generally comparable annual base salary, incentive pay and employee benefits from CONSOL Energy for a period not extending beyond the two year anniversary of the Change in Control (the “reemployment period”). If the Executive refuses or fails to accept CONSOL Energy’s offer of reemployment, the Executive will not be considered to have terminated employment under the agreement and will not receive any benefits thereunder.

Upon any reemployment, the Executive must agree and acknowledge that no compensation and benefits will be payable to the Executive under the agreement, except by CONSOL Energy during the reemployment period and the Executive will terminate his agreement with CNX Gas and execute a new change in control severance agreement with CONSOL Energy. If, however, CONSOL Energy terminates the Executive’s employment with it during the reemployment period, CONSOL Energy will have to pay the Executive the change in control payments and benefits described above offset by any salary, incentive pay and months of benefits, as applicable, received by the Executive from CONSOL Energy during the reemployment period.

In the event the Executive is terminated under circumstances described above and CONSOL Energy does not exercise its right to reemploy the Executive (in the case of Messrs. DeIuliis and Bench), CNX Gas may, in its sole discretion, elect to delay any Executive’s termination date for up to 24 months (the “consultancy period”). During the consultancy period, the Executive must be available to provide advice and assistance to CNX Gas. In no event may the Executive be required to provide more than five (5) hours of consulting services per work week without his consent and the Executive shall be permitted to engage in other business activities, subject to certain restrictions. If CNX Gas elects to provide for a consultancy period, the Executive will continue to receive his annual base salary and employee benefits during the consultancy period and the change in control payments and benefits described above will be offset by such amounts and benefits provided to the Executive during the consultancy period.

With respect to each of Messrs. DeIuliis, Smith, Bench and Johnson, if it is determined that any payment or distribution (a “Payment”) by CNX Gas to or for his benefit would constitute an “excess parachute payment” within the meaning of section 280G of the Code, CNX Gas will pay to him an additional amount (the “Gross-Up Payment”), subject to certain limitations, such that the net amount retained by him after deduction of any excise tax imposed under section 4999 of the Code, and any tax imposed upon the Gross-Up Payment, will be equal to the Payment.

The change in control severance agreements contain confidentiality, non-competition and non-solicitation obligations.

The change in control severance agreements will be in effect until July 21, 2006, subject to an annual one-year extension commencing on January 1, 2006, unless CNX Gas gives notice not later than October 31 of the preceding year that it does not wish to extend the agreement. Regardless of any such notice by CNX Gas, the agreement will continue in effect for a period of 24 months beyond the term provided in the agreement if a Change in Control occurs during the period the agreement is in effect.

CNX Gas Equity Incentive Plan

We have adopted the CNX Gas Equity Incentive Plan. 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 three 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’s equity incentive plan. As of September 9, 2005 our board has granted 92,969 shares of common stock underlying restricted stock units and 1,028,926 shares of common stock underlying stock options to officers, directors and employees of CNX Gas.

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’s plan is 2,500,000. No participant receiving an award will be granted: (i) options or stock appreciation rights with respect to more than 350,000 shares during any fiscal year; (ii) performance awards (denominated in shares) which result in a participant receiving more than 150,000 shares for each full or partial fiscal year of CNX Gas contained in the performance period of a particular performance award; or (iii) awards denominated in cash which could result in such participant receiving more than $1,200,000 for each full or partial fiscal year of CNX Gas contained in the performance period of a particular performance award. If any shares of common stock covered by or related to an award granted under CNX Gas’s plan are forfeited, or if such an award is settled for cash, otherwise terminated or canceled without the delivery of shares of common stock, then the shares covered by or related to such award, or the number of shares otherwise counted against the aggregate number of shares of common stock with respect to which awards may be granted, to the extent of any such settlement, forfeiture, termination or cancellation, will again become shares with respect to which awards may be granted.

Stock Options. CNX Gas’ equity incentive plan permits the granting of options, both incentive stock options (“ISOs”) and non-qualified stock options (“NQOs”), to purchase shares of CNX Gas common stock. The board of directors establishes the exercise price at the time each option is granted. CNX Gas’s equity incentive plan provides that the option exercise price for each share covered by an option, including ISOs and NQOs, must equal or exceed the fair market value of a share of CNX Gas common stock on the date the option is granted, and that the term of the option may not exceed ten years from the date of the grant.

The exercise price of options granted under the plan may be paid for by cash, or its equivalent, or by exchanging shares of CNX Gas common stock (owned by the participant for at least six months and which are not the subject of any pledge or other security interest) with a fair market value on the exercise date equal to the aggregate exercise price of the options, or by a combination of the foregoing. The board of directors shall determine whether in its discretion a participant may elect to pay all or any portion of the aggregate exercise price by having shares with a fair market value on the date of exercise equal to the aggregate exercise price withheld by CNX Gas or sold by a broker-dealer.

The plan also provides that the board of directors may provide in an award agreement for the automatic grant of a restoration option to a participant who delivers shares in payment of the exercise price of any option granted under the plan, or in the event that the withholding tax liability arising upon exercise of any such option

or option by a participant is satisfied through the withholding by CNX Gas of shares otherwise deliverable upon exercise of the option. A restoration option entitles the holder to purchase a number of shares equal to the number of such shares delivered or withheld upon exercise of the original option. A restoration option must have an exercise price of not less than 100% of the fair market value on the grant date. As of August 12, 2005, the board of directors has not granted any options with a restoration provision.

Stock Appreciation Rights. Stock Appreciation Rights (“SARs”) may be granted in tandem with another award, in addition to another award, or freestanding and unrelated to another award. SARs granted in tandem with or in addition to an award may be granted either at the same time as the award or, except in the case of ISOs, at a later time. SARs are not exercisable earlier than six months after the date granted. SARs will have grant prices no less than the fair market value of a share of CNX Gas common stock on the grant date and will have terms no longer than ten years.

SARs entitle the participant to receive an amount equal to the excess of the fair market value of a share of CNX Gas common stock on the date of exercise of the SAR over the grant price. The board of directors determines whether a SAR is settled in cash, shares or a combination of cash and shares. A SAR settled in shares of common stock will be counted in full against the number of shares available for awards under the plan, regardless of the number of shares of common stock issued upon settlement of the SAR.

Restricted Stock and Restricted Stock Units. Restricted stock and restricted stock units may also be granted under CNX Gas’s equity incentive plan. The board of directors determines the number of shares of restricted stock and/or the number of restricted stock units to be granted to each participant, the duration of such awards, and the conditions under which, the restricted stock and restricted stock units may be forfeited to CNX Gas, and the other terms and conditions of such awards.

Shares of restricted stock and restricted stock units may not be sold, assigned, transferred, pledged or otherwise encumbered, except, in the case of restricted stock, as provided in CNX Gas’s equity incentive plan or the applicable award agreements. Each restricted stock unit has a value equal to the fair market value of a share. Restricted stock units may be paid in cash, shares, other securities or other property.

Performance Awards. Performance awards may also be granted under CNX Gas’s equity incentive plan. A “Performance Award” consists of a right that is:

•

denominated in cash, shares of CNX Gas common stock or options;

•

valued, as determined by the board of directors, in accordance with the achievement of such performance goals during such performance periods as the board of directors shall establish; and

•

payable at such time and in the form as the board of directors determines.

Performance Awards may be paid in a lump sum or in installments following the close of the performance period or on a deferred basis.

For awards intended to be performance-based compensation under Section 162(m) of the Code, performance awards will be conditioned upon the achievement of pre-established goals relating to one or more of the following performance measures (subject to such modifications as specified by the board): cash flow; cash flow from operations; earnings (including earnings before interest, taxes, depreciation, and amortization or some variation thereof); earnings per share, diluted or basic; earnings per share from continuing operations; net asset turnover; inventory turnover; capital expenditures; debt, debt reduction; working capital; return on investment; return on sales; net or gross sales; market share; economic value added; cost of capital; change in assets; expense reduction levels; productivity; delivery performance; safety record; stock price; return on equity; total stockholder return; return on capital; return on assets or net assets; revenue; income or net income; operating income or net operating income; operating profit or net operating profit; gross margin, operating margin or profit margin; and completion of acquisitions, business expansion, product diversification and other non-financial operating and management performance objectives.

To the extent consistent with Section 162(m) of the Code, the board of directors may determine that certain adjustments will apply, in whole or in part, in such manner as determined by the board of directors, to exclude the affect of any of the following events that occur during a performance period: the impairment of tangible or intangible assets; litigation or claim judgments or settlements; the effect of changes in tax law, accounting principles or other such laws or provisions affecting reported results; accruals for reorganization and restructuring programs, including, but not limited to, reductions in force and early retirement incentives; currency fluctuations; and any extraordinary, unusual, infrequent or non-recurring items, including, but not limited to, such items described in management’s discussion and analysis of financial condition and results of operations or the financial statements and notes thereto appearing in CNX Gas’ annual report to stockholders for the applicable year. Performance measures may be determined either individually, alternatively or in any combination, applied to either CNX Gas as a whole or to a business unit or subsidiary entity thereof, either individually, alternatively or in any combination, and measured over a period of time including any portion of a year, annually or cumulatively over a period of years, on an absolute basis or relative to a pre-established target, to previous years’ results or to a designated comparison group, in each case as specified by the board of directors.

The board may, in its discretion, also establish such additional restrictions or conditions that must be satisfied as a condition precedent to the payment of all or a portion of any performance award. The board of directors may also reduce the amount of any performance award if it concludes that such reduction is necessary or appropriate based on: (i) an evaluation of such participant’s performance, (ii) comparisons with compensation received by other similarly situated individuals working within CNX Gas’s industry, (iii) the CNX Gas’s financial results and conditions, or (iv) such other factors or conditions that the board deems relevant; provided that the board of directors will not have the discretion to increase any award that is intended to be performance-based compensation under Section 162(m) of the Code.

Other Stock-Based Awards. Other stock-based awards may also be granted under CNX Gas’s equity incentive plan. An “Other Stock-Based Award” consists of any right that is:

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not an award described above; and

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an award of shares or an award denominated or payable in, valued in whole or in part by reference to, or otherwise based on or related to, shares (including, without limitation, securities convertible into shares), as deemed by the board of directors to be consistent with the purposes of CNX Gas’s equity incentive plan.

Change in Control. In the event that we engage in a transaction constituting a change in control, the board of directors shall have complete authority and discretion, but not the obligation, to accelerate the vesting of outstanding awards and the termination of restrictions on shares. As part of any agreement in connection with a change in control, the board of directors may also negotiate terms providing protection for participants, including, the assumption of any awards outstanding under the plan or the substitution of similar awards for those outstanding under the plan.

In connection with a Change in Control or dividend or other distribution, recapitalization, stock split, reverse stock split, reorganization, merger, consolidation, split-up, spin-off, combination, repurchase, or exchange of shares or other securities or such other events as determined by the board of directors and set forth in an agreement, the board of directors may, in its discretion: (i) cancel any or all outstanding awards under the plan in consideration for payment to the holder of each such cancelled award of an amount equal to the portion of the consideration that would have been payable to such holder pursuant to such transaction if such award had been fully vested and exercisable, and had been fully exercised, immediately prior to such transaction, less the exercise price if any that would have been payable therefor, or (ii) if the net amount referred to in clause (i) would be negative, cancel such award for no consideration or payment of any kind. Payment of any amount payable pursuant to the preceding sentence may be made in cash and/or securities or other property in the board of director’s discretion.

Amendment and Termination. The board of directors may amend, suspend, discontinue or terminate the plan, any award agreement or any portion thereof at any time; provided that no such amendment, alteration, suspension, discontinuation, termination will be made without: (i) stockholder approval if such approval is necessary to comply with tax or regulatory requirements or (ii) the consent of the affected participant, if such action would adversely affect any material rights of such participant under any outstanding award. Notwithstanding the foregoing or any provision of the plan to the contrary, the board of directors may at any time (without the consent of participants) modify, amend, or terminate any or all of the provisions of the plan to the extent necessary: (i) to conform the provisions of the plan with Section 409A of the Code and (ii) to enable the plan to achieve its stated purposes in any jurisdiction outside the United States in a tax-efficient manner and in compliance with local rules and regulations.

CONSOL Energy Equity Incentive Plan

The CONSOL Energy equity incentive plan became effective on May 3, 2005. Some of CONSOL Energy’s employees (including our three executive officers) and non-employee directors have participated in or have been eligible to participate and, will continue to be eligible to participate in CONSOL Energy’s equity incentive plan and to receive incentive-based compensation under that plan. CONSOL Energy’s equity incentive plan is administered by CONSOL Energy’s board of directors. Except with respect to awards made pursuant to Section 10 of CONSOL Energy’s equity incentive plan to non-employee directors of CONSOL Energy or any affiliate (“Eligible Directors”), its board of directors may delegate any or all authority for administration of the Plan to a committee of the board of directors.

Shares Available for Awards; Limitations. The total number of shares of CONSOL Energy common stock with respect to which awards may be granted under CONSOL Energy’s equity incentive plan is 9,100,000, out of which 1,300,000 may currently be used with respect to awards other than options. The maximum number of shares that may be subject to incentive stock option grants is 9,100,000. Subject to adjustment, the maximum number of shares with respect to which awards may be granted to any participant during a calendar year is 1,000,000 shares. The maximum annual number of shares in respect of which restricted stock awards, restricted stock units, performance awards and other stock-based awards may be granted under CONSOL Energy’s equity incentive plan to any participant is 325,000 and the maximum annual amount of any award settled in cash with respect to any participant is $2,000,000. If any shares of common stock covered by or related to an award granted under CONSOL Energy’s equity incentive plan are forfeited, or if such an award is settled for cash, otherwise terminated or canceled without the delivery of shares of common stock, then the shares covered by or related to such award, or the number of shares otherwise counted against the aggregate number of shares of common stock with respect to which awards may be granted, to the extent of any such settlement, forfeiture, termination or cancellation, will again become shares with respect to which awards may be granted.

Stock Options. CONSOL Energy’s equity incentive plan permits the granting of options, both ISOs and NQOs, to purchase shares of CONSOL Energy common stock. CONSOL Energy’s board of directors establishes the exercise price at the time each option is granted. CONSOL Energy’s equity incentive plan provides that the option exercise price for each share covered by an option, including ISOs and NQOs, must equal or exceed the fair market value of a share of CONSOL Energy common stock on the date the option is granted, and that the term of the option may not exceed ten years from the date of the grant.

The exercise price of options granted under CONSOL Energy’s equity incentive plan may be paid for by cash, or its equivalent, or by exchanging shares of CONSOL Energy common stock (owned by the participant for at least six months and which are not the subject of any pledge or other security interest) with a fair market value on the exercise date equal to the aggregate exercise price of the options, or by a combination of the foregoing. A participant may elect to pay all or any portion of the aggregate exercise price by having shares with a fair market value on the date of exercise equal to the aggregate exercise price withheld by CONSOL Energy, or sold by a broker-dealer.

CONSOL Energy’s equity incentive plan also provides that its board of directors may provide in an award agreement for the automatic grant of a restoration option to a participant who delivers shares in payment of the

exercise price of any option granted under CONSOL Energy’s equity incentive plan, or in the event that the withholding tax liability arising upon exercise of any such option or option by a participant is satisfied through the withholding by CONSOL Energy of shares otherwise deliverable upon exercise of the option. A restoration option entitles the holder to purchase a number of shares equal to the number of such shares delivered or withheld upon exercise of the original option. A restoration option must have an exercise price of not less than 100% of the fair market value on the grant date. As of August 12, 2005, CONSOL Energy’s board of directors has not granted any options with a restoration provision.

Stock Appreciation Rights. SARs may be granted under CONSOL Energy’s equity incentive plan to any employee or Eligible Director of CONSOL Energy or any affiliate. SARs may be granted in tandem with another award, in addition to another award, or freestanding and unrelated to another award. SARs granted in tandem with or in addition to an award may be granted either at the same time as the award or, except in the case of ISOs, at a later time. SARs are not exercisable earlier than six months after the date granted. SARs will have grant prices no less than fair market value of a share of CONSOL Energy common stock on the grant date and will have terms of no longer than ten years.

SARs entitle the participant to receive an amount equal to the excess of the fair market value of a share of CONSOL Energy common stock on the date of exercise of the SAR over the grant price. CONSOL Energy’s board of directors determines whether a SAR is settled in cash, shares or a combination of cash and shares. A SAR settled in shares of common stock will be counted in full against the number of shares available for awards under CONSOL Energy’s equity incentive plan, regardless of the number of shares of common stock issued upon settlement of the SAR.

Restricted Stock and Restricted Stock Units. Restricted stock and restricted stock units may also be granted under CONSOL Energy’s equity incentive plan to any employee or Eligible Director of CONSOL Energy or any affiliate. CONSOL Energy’s board of directors determines the number of shares of restricted stock and/or the number of restricted stock units to be granted to each participant, the duration such awards, and the conditions under which, the restricted stock and restricted stock units may be forfeited to CONSOL Energy, and the other terms and conditions of such awards.

Shares of restricted stock and restricted stock units may not be sold, assigned, transferred, pledged or otherwise encumbered, except, in the case of restricted stock, as provided in CONSOL Energy’s equity incentive plan or the applicable award agreements. Each restricted stock unit has a value equal to the fair market value of a share. Restricted stock units may be paid in cash, shares, other securities or other property.

Performance Awards. Performance awards may also be granted under CONSOL Energy’s equity incentive plan to any employee of CONSOL Energy or any affiliate. A “Performance Award” consists of a right that is:

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denominated in cash or shares of CONSOL Energy common stock;

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valued, as determined by the board of directors, in accordance with the achievement of such performance goals during such performance periods as the board of directors shall establish; and

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payable at such time and in the form as the board of directors determines.

Performance Awards may be paid in a lump sum or in installments following the close of the performance period or on a deferred basis.

Other Stock-Based Awards. Other stock-based awards may also be granted under CONSOL Energy’s equity incentive plan. An “Other Stock-Based Award” consists of any right that is:

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not an award described above; and

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shares), as deemed by the board of directors to be consistent with the purposes of CONSOL Energy’s equity incentive plan.

Eligible Directors. Eligible Directors are eligible for awards under CONSOL Energy’s equity incentive plan. As of September 30, 2005, there were six Eligible Directors eligible to receive awards under CONSOL Energy’s equity incentive plan. Upon an Eligible Directors’ initial election to the board of directors, the Eligible Director receives a NQO to acquire 4,000 shares (“Initial Grant”).

Effective as of the date of each annual meeting of CONSOL Energy’s stockholders at which directors are elected or re-elected to the board of directors, CONSOL Energy’s equity incentive plan provides that each Eligible Director who has not received an Initial Grant since the immediately preceding annual meeting of CONSOL Energy’s stockholders is entitled to receive a NQO to acquire 2,500 shares (“Annual Grant”). The CONSOL Energy equity incentive plan provides that the board of directors, in its sole discretion, may grant other types of awards to Eligible Directors in lieu of all or any portion of any Initial Grant or Annual Grant.

The exercise price per share of each NQO granted to an Eligible Director is the fair market value of a share on the grant date. The NQOs granted to Eligible Directors vest ratably and become exercisable in one-third increments on each anniversary of the grant date and expire ten years from the grant date. Unvested NQOs granted to Eligible Directors immediately vest and become exercisable if an individual ceases to be a director on account of death, disability or retirement at normal retirement age for directors, and shall remain exercisable until the normal expiration of the option. Upon termination as a director for any other reason other than cause, unvested NQOs are forfeited and vested NQOs remain exercisable for three months following the termination date. Upon termination as a director for cause, all NQOs (whether or not vested) shall be forfeited as of the termination date.

The CONSOL Energy board of directors may grant deferred stock units to Eligible Directors in lieu of all or any portion of the annual retainer or meeting fees otherwise payable to the Eligible Directors. Each deferred stock unit entitles the Eligible Director to receive one share or an amount of cash equal to the fair market value of a share on the payment date on terms and conditions as determined by the board of directors. The amendments to CONSOL Energy’s equity incentive plan allow Eligible Directors to elect to receive deferred stock units in lieu of all or any portion of the annual retainer or meeting fees otherwise payable to the Eligible Director in cash. Eligible Directors may elect to defer receipt of shares or cash to be paid pursuant to deferred stock units in accordance with a deferred compensation policy established by CONSOL Energy.

Amendment and Termination. CONSOL Energy’s equity incentive plan may be amended, altered, suspended, discontinued, or terminated at any time; provided that no such amendment, alteration, suspension, discontinuation or termination will be made without stockholder approval if approval is necessary to comply with any tax or regulatory requirement for which or with which CONSOL Energy’s board of directors deems it necessary or desirable to comply. In addition, the proposed amendments provide that no such amendment, alteration, suspension, discontinuation or termination may be made without stockholder approval if it would constitute a repricing of a stock option or a stock settled SAR.

CONSOL Energy’s board of directors may waive any conditions or rights under, amend any terms of, or alter, suspend, discontinue, cancel or terminate, any award granted, prospectively or retroactively; provided that any such waiver, amendment, alteration, suspension, discontinuance, cancellation, or termination that would adversely affect the rights of any participant or any holder or beneficiary of any award previously granted does not to that extent become effective without the consent of the affected participant, holder, or beneficiary. CONSOL Energy’s equity incentive plan provides that a cancellation of an award in exchange for a cash payment by CONSOL Energy may only be effected if the payment does not violate the requirements of Section 409A of the Code.

RELATIONSHIP WITH CONSOL ENERGY AND

CERTAIN TRANSACTIONS WITH AFFILIATES AND MANAGEMENT

Intercompany Agreements with CONSOL Energy

We have provided below a summary description of the master separation agreement between CONSOL Energy and us and the other key agreements that relate to our separation from CONSOL Energy which we entered into as part of our separation from CONSOL Energy. This description, which summarizes the material terms of these agreements, is not complete. We urge you to read the full text of these agreements, which may be obtained by written request from CNX Gas. References in this section to CONSOL Energy include its subsidiaries and references to our company include our subsidiaries. These agreements are not the result of arm’s-length negotiation.

Overview

The master separation agreement contains the key provisions related to our separation from CONSOL Energy. The other agreements referenced in the master separation agreement govern various interim and ongoing relationships between CONSOL Energy and us. These agreements include:

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the master cooperation and safety agreement;

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the registration rights agreement;

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the tax sharing agreement;

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the services agreement; and

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the intercompany revolving credit agreement.

Master Separation Agreement

Overview. The master separation agreement contains the key provisions relating to the separation of our business from CONSOL Energy’s other businesses and sets forth certain agreements and covenants related to certain ongoing relationships between CONSOL Energy and us following the separation of those businesses.

Contribution of Assets; Assumption of Liabilities. CONSOL Energy and certain of its affiliates transferred to CNX Gas the assets that are used exclusively in CONSOL Energy’s gas operations and other assets specifically listed in the agreement, subject to some specified exclusions. These assets included in particular coalbed methane and conventional oil and gas rights located in Virginia, Pennsylvania and northern West Virginia. All assets were transferred to CNX Gas on an “as-is-where-is” basis, which means that we bear all the risk of a failure of title on any of the assets. In the event that both CNX Gas and CONSOL Energy have rights under certain contracts, the party that signed the contract will make available the rights and benefits of that contract to the other party, but only to the extent that the contract applies to the other party, and the other party will assume and discharge the liabilities related to those rights and benefits. CNX Gas assumed all of the liabilities related to those assets and the gas operations, even if those liabilities were as a result of activities occurring prior to the effective date of the separation of the businesses and regardless of whether such liabilities were the result of negligence or misconduct on the part of CONSOL Energy, subject to the following allocation of unknown liabilities, if any, asserted in writing by one or more third parties prior to the fifth anniversary following August 8, 2005: 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 during this five year period. Certain excluded liabilities which may have related to gas operations were not assumed by us and we are being indemnified by CONSOL Energy with respect to these. Some of the excluded liabilities may have been incurred by our subsidiaries, which would have to satisfy those liabilities if CONSOL Energy failed to satisfy them.

The coalbed methane and conventional oil and gas rights located in Virginia, Pennsylvania, northern West Virginia and Tennessee held by CNX Gas after our separation from CONSOL Energy represent substantially all of our proved reserves. In addition to the transfers made to CNX Gas in the separation, CONSOL Energy leased to us pursuant to a master lease substantially all other coalbed methane and conventional oil and gas rights that CONSOL Energy and its majority-owned subsidiaries hold in the United States. These leased assets are principally located outside of Virginia, Pennsylvania, northern West Virginia and Tennessee. The master lease provided for a one-time payment of $50,000 at its inception. The master lease has 99-year term and by its terms no royalty is payable under the lease.

Special Dividend. In connection with the separation, we paid a special dividend in an amount equal to the net proceeds from the private placement of the shares of CNX Gas which was approximately $420.2 million to CONSOL Energy.

Covenants. We have agreed that, for so long as CONSOL Energy beneficially owns at least fifty percent (50%) of our outstanding voting stock, we will:

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not take any action which would limit the ability of CONSOL Energy or its transferee to transfer its shares of our common stock; and

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not take any actions that could reasonably result in CONSOL Energy being in breach of or in default under any contract or agreement, including any action that would cause a default under CONSOL Energy’s debt instruments.

Additionally, we will not issue any additional capital stock without CONSOL Energy’s consent if after such issuance CONSOL Energy would own less than eighty percent (80%) of our outstanding voting stock.

Option Rights. We have granted CONSOL Energy the right to purchase shares of our capital stock in two instances. First, CONSOL Energy has the right to purchase shares of our capital stock in order to maintain a percentage ownership in our capital stock of at least eighty percent (80%) for tax consolidation purposes. Second, CONSOL Energy has the right to purchase the required number of shares of capital stock from us so that it may effect a distribution of all of its CNX Gas shares to its stockholders as a tax-free spin-off. The exercise price for any of our shares purchased by CONSOL Energy is the then market price for our shares (defined as the average of the last sales price on each of the immediately preceding five trading days) on the securities exchange or quotation system on which our stock is listed).

We have agreed not to buy or sell any assets, dispose of any assets, or acquire any equity or debt securities of a third party in each case in excess of $30 million without CONSOL Energy’s prior consent.

Financial and Other Information. We have agreed that, for so long as CONSOL Energy is required to consolidate our results of operations and financial position with its own or account for its investment in our company on the equity method of accounting, we will:

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maintain disclosure controls and procedures and internal controls over financial reporting to the same extent as a public company would be required and file or furnish to the Commission the necessary certificates, reports and other information (to the extent that we are required to make such filings by the Commission);

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maintain a fiscal year that ends on the same date as CONSOL Energy’s fiscal year;

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provide to CONSOL Energy (prior to filing) drafts of the quarterly and annual periodic reports we file with the Commission and all other reports, notices and proxy information we are required to file with the Commission and file our quarterly and annual reports no later than the date on which CONSOL Energy files its quarterly and annual reports; and

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provide to CONSOL Energy annual budgets, projections, press releases and other information they request.

Auditors and Audits; Annual Statements and Accounting. We have agreed that, for so long as CONSOL Energy is required to consolidate our results of operations and financial position with its own, we will:

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use commercially reasonable efforts to enable our independent auditors to complete their audit of our financial statements in a timely manner so as to permit timely filing of CONSOL Energy’s financial statements;

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provide to CONSOL Energy and its independent auditors all information required for CONSOL Energy to meet its schedule for the filing and distribution of its financial statements and to make available to CONSOL Energy and its independent auditors all documents necessary for the annual audit of our company as well as access to the responsible company personnel so that CONSOL Energy and its independent auditors may conduct their audits relating to our financial statements; and

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adhere to certain specified CONSOL Energy accounting policies and notify and consult with CONSOL Energy regarding any changes to our accounting principles and estimates used in the preparation of our financial statements subject to applicable law and approval of our audit committee.

Indemnification. Under the master separation agreement, we and CONSOL Energy indemnify and release each other as follows:

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we indemnify and hold harmless CONSOL Energy and its affiliates and their respective officers, directors, employees, agents, successors and assigns against any losses, liabilities, damages, claims and expenses arising out of or relating to the assumed liabilities and our assets, businesses and operations and other assets, businesses operated or managed by us;

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CONSOL Energy similarly indemnifies us and our affiliates and our and their respective officers, directors, employees, agents, successors and assigns for the excluded liabilities and for CONSOL Energy’s future assets, businesses and operations; and

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we indemnify CONSOL Energy and its affiliates against all liabilities arising out of federal and state securities laws, including liabilities related to material untrue statements and omissions in this prospectus, any future registration statement we file with the SEC and any future prospectus we use in a public offering. However, our indemnification of CONSOL Energy does not apply to information relating to CONSOL Energy supplied by CONSOL Energy, excluding information relating to us. Furthermore, insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling us pursuant to the foregoing provisions, we have been informed that in the opinion of the SEC such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable.

All indemnification amounts will be reduced by any insurance proceeds and other offsetting amounts recovered by the party entitled to indemnification. In addition, the services agreement, the registration rights agreement and the tax matters agreement referred to below provide for indemnification between us and CONSOL Energy relating to the substance of such agreements.

Access to Information. Under the master separation agreement, we and CONSOL Energy are obligated to provide each other access to information as follows:

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subject to applicable confidentiality obligations and other restrictions, we and CONSOL Energy will give each other any information within each other’s possession that the requesting party reasonably needs to comply with requirements imposed on the requesting party by a governmental authority, for use in any proceeding or to satisfy audit, accounting or similar requirements, or to comply with its obligations under the master separation agreement or any ancillary agreement;

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we and CONSOL Energy will use reasonable efforts to make available to each other’s past and present directors, officers, other employees and agents as witnesses in any legal, administrative or other proceeding in which the other party may become involved;

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the company providing information, consultant or witness services under the master separation agreement will be entitled to reimbursement from the other for reasonable expenses incurred in providing this assistance; and

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we and CONSOL Energy will each agree to hold in strict confidence all information concerning or belonging to the other for a period of up to three years following termination of the master separation agreement.

Termination and Assignment. The master separation agreement may be terminated by the mutual consent of CONSOL Energy and us. Various covenants in the master separation agreement terminate if we are no longer a subsidiary of CONSOL Energy. This agreement may not be assigned by us without the other party’s prior written consent, which consent may be withheld in such party’s sole discretion, however, CONSOL Energy may assign this agreement in connection with a merger in which it is not the surviving entity or in the event it transfers all or substantially all of its assets.

Expenses. CONSOL Energy is responsible for paying costs (including all associated third-party costs) incurred in connection with the transactions contemplated by the master separation agreement that occur on or prior to the separation (August 8, 2005). We are responsible for any costs incurred by us related to the master separation agreement following such date.

Master Cooperation and Safety Agreement

Overview. The master cooperation and safety agreement contains the provisions related to the safe and economical operation of our gas business and CONSOL Energy’s coal business where we have joint interests.

Overriding Principles. The parties have agreed that to the extent there is any conflict between our gas interests and CONSOL Energy’s coal interest in a joint location, CONSOL Energy’s coal operations shall generally prevail. We have agreed to sign and deliver any waiver or consent necessary to allow coal mining operations of CONSOL Energy in the vicinity of any property or gas rights owned by us and CONSOL Energy has agreed that we have the right to capture gas from any well associated with CONSOL Energy’s property, subject to CONSOL Energy’s right to preclude us from capturing gas with respect to any active mining area in order to promote safety for and productivity of its coal operations. We will receive all proceeds from the capture of gas in all wells. In order to coordinate our operational relationship with CONSOL Energy, we will coordinate our annual drilling plan with CONSOL Energy’s ten year mine plan.

Wells and Capturing Gas. We have the ability to locate and drill wells and capture gas for marketing, at our sole discretion, in all non-coal areas. With respect to an active mining area or within CONSOL Energy’s then ten year mining plan (i.e., a coal area), CONSOL Energy has the right to drill wells but not to capture and market gas. CONSOL Energy has this right because it must de-gas coal mines prior to coal production for safety reasons. CONSOL Energy also pays for all of the costs of drilling these wells. If we determine it is economical to capture gas from a CONSOL Energy coal area well, we have the right to capture and market this gas. In addition to the CONSOL Energy coal area wells, we also have the right (with CONSOL Energy’s consent which it cannot unreasonably withhold) to locate and drill additional wells and capture gas for marketing in the coal area. Subject to the overriding principles stated above, we have the sole right to capture gas in any active mining area, in any area in the ten year mine plan and in any other non-coal area from wells developed by CONSOL Energy or us. To the extent that CONSOL Energy mines through any non-coal area well, it is obligated to reimburse us for the loss of that well, including any assets we lost because of the mine through. We are generally responsible for plugging the wells in non-coal areas and CONSOL Energy is generally responsible for plugging the wells in coal areas.

Control Systems. We will own, operate and maintain all of our master control systems. However, CONSOL Energy will have access to the system in coal areas for monitoring purposes. CONSOL Energy can also request that we relocate, at CONSOL Energy’s expense, any part of our system to the extent it interferes with their coal operations. CONSOL Energy is also permitted to subside any part of a system located in an active mine area, provided that they reimburse us for our out-of-pocket costs related to the subsidence.

Regulatory Matters and Litigation. We will be responsible for obtaining all necessary permits, title reports, licenses and bonds related to wells in all non-coal areas and the capture of gas in all non-coal and coal areas. CONSOL Energy is responsible for the same matters with respect to all coal area wells, except for wells

drilled or recompleted at our election. In general, we will be responsible for all regulatory matters involving the gas assets and will cooperate with CONSOL Energy in the resolution of all regulatory matters and litigation matters where the rights or obligations of both parties may be implicated.

Compliance and Safety Standards. CONSOL Energy’s employees and contractors and our employees and contractors are required, while on the other’s property, to comply with the more stringent of its own or the other party’s safety policies.

Additional Rights of CONSOL Energy. CONSOL Energy maintains all mining rights to use the surface within any coal area for activities associated with coal mining, including venting coal gas and drilling vertical vent holes for degasification. CONSOL Energy also has the right to use any coal gas produced from coal area wells as long their use is consistent with past practices and they pay us the applicable market price for the use of the gas.

Corporate Opportunities and Rights of First Refusal. We and CONSOL Energy have agreed upon an allocation of corporate opportunities which is described in “Description of Capital Stock—Important Information Contained in the Certificate of Incorporation and Bylaws—Corporate Opportunities and Conflicts of Interest.” We and CONSOL Energy have agreed that as long as CONSOL Energy beneficially owns 10% or more of our voting stock, we will have a right of first refusal on future gas rights obtained by CONSOL Energy and it will have a right of first refusal on any coal rights that we may acquire.

Indemnity. We are obligated to indemnify CONSOL Energy from any claims, damages, losses and other liabilities arising from personal injury or property damage resulting solely from our negligence in conducting our business in any coal and non-coal area. CONSOL Energy is obligated to indemnify us from any claims, damages, losses and other liabilities arising from personal injury or property damage resulting solely from its negligence in conducting its business in any coal and non-coal area. CONSOL Energy’s indemnification obligations will not apply in the event any of those damages or losses were the result of subsidence or other effects of their full extraction mining.

Registration Rights Agreement

CONSOL Energy cannot freely sell all shares of our common stock without registration under the Securities Act or a valid exemption under it. Accordingly, we entered into a registration rights agreement with CONSOL Energy to provide it with registration rights relating to the shares of our common stock which it holds. Under the registration rights agreement, CONSOL Energy has the right to require us to register for offer and sale all or a portion of our common stock held by CONSOL Energy. Please see the description under “Registration Rights” on page 126 for a summary of CONSOL Energy’s rights under the registration rights agreement.

Tax Sharing Agreement

CONSOL Energy and we entered into a tax sharing agreement. The tax sharing agreement governs the respective rights, responsibilities, and obligations of CONSOL Energy and us with respect to certain tax liabilities and benefits, tax attributes, tax contests and other matters regarding income taxes and related tax returns. The following is a general summary of the tax sharing agreement.

In general, under the tax sharing agreement:

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CONSOL Energy is responsible for the remittance of U.S. federal income taxes of the affiliated group of corporations, including us, of which it is the common parent;

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CONSOL Energy is responsible for the remittance of state income taxes to states in which it is required to file, or elects to file a consolidated or combined state income tax return; and

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we are obligated to pay to CONSOL Energy, each year, an amount equal to the amount of U.S. federal income tax and state income tax that we would have incurred had we filed a separate U.S. federal income tax return and separate state income tax returns in these states in which we are included in a consolidated or combined state tax return filed by CONSOL Energy.

CONSOL Energy is responsible for, and has exclusive control over, preparing and filing any tax return with respect to the CONSOL Energy affiliated group for U.S. federal income tax purposes and with respect to any consolidated, combined or unitary group for state tax purposes that includes CONSOL Energy or any of its subsidiaries, including making any tax elections, provided, however, that any tax election that affects only us shall be made, after CONSOL Energy consults with us, in a manner that is reasonable and fair to us. Under the tax sharing agreement, we will be responsible for preparing and filing any tax returns that include only us and our subsidiaries.

CONSOL Energy generally has exclusive authority to control tax examinations and proceedings related to any tax returns of the CONSOL Energy affiliated group for U.S. federal income tax purposes and with respect to any consolidated, combined or unitary group for state tax purposes that includes CONSOL Energy or any of its subsidiaries, except for matters or issues that relate solely to us. We generally have exclusive authority to control tax examinations and proceedings with respect to tax returns that include only us and our subsidiaries and portions of other tax examinations and proceedings which relate solely to our tax liability.

Under the tax sharing agreement we covenant to take certain action and refrain from certain actions in order to preserve CONSOL Energy’s ability to distribute our stock to its shareholders in a tax-free spin-off.

The tax sharing agreement also assigns responsibilities for other administrative matters and provides for cooperation and information sharing with respect to tax matters.

Services Agreement

The services agreement governs the provision by CONSOL Energy to us of support services, such as:

•

cash management and debt service administration;

•

accounting and tax;

•

investor relations;

•

payroll and human resources administration;

•

legal;

•

information technology;

•

internal audit;

•

real estate management; and

•

other general administrative functions.

We have also agreed to pay or reimburse CONSOL Energy for any out-of-pocket payments, costs and expenses associated with these services. The agreement shall extend until terminated by the mutual agreement of the parties.

Intercompany Revolving Credit Agreement

CNX Gas and CONSOL Energy entered into an intercompany credit agreement under which we were permitted to borrow up to $50 million at any one time outstanding with interest on borrowings at a rate equal to the all-in interest rate available to CONSOL Energy from outside sources for short term borrowings. The intercompany credit agreement terminated effective October 7, 2005 when we entered into our new $200 million credit agreement with third party commercial lenders. See “Management’s Discussion and Analysis of Results of Operation and Financial Condition—Liquidity and Capital Resources.”

Other Transactions

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 purchases various supplies from CONSOL Energy’s wholly-owned subsidiary Fairmont Supply. The cost of these items reflects then current market prices and is included in cost of goods sold as an arms-length transaction. Management of CNX Gas believes that these are on terms no less

favorable than could be obtained from unaffiliated third parties. In the years ended December 31, 2004, 2003 and 2002 CNX Gas’ sales of gas to CONSOL Energy were for $3.6, $3.3 and $2.1 million, respectively. In the years ended December 31, 2004, 2003 and 2002 CNX Gas’ purchases of supplies from Fairmont Supply equaled $137, $89 and $89 thousand, respectively. Management of CNX Gas expects that future sales of gas to CONSOL Energy and purchases of supplies from CONSOL Energy will be on terms no less favorable than could be obtained from unaffiliated third parties.

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 has been conducted by CONSOL Energy. This arrangement allowed CNX Gas to obtain funds from CONSOL Energy at any time. These amounts were considered to be a capital contribution from, or a return of capital to, CONSOL Energy. No interest was charged or paid under that arrangement. In the twelve months ended December 31, 2004 and 2003 CNX Gas paid net cash to CONSOL Energy of $82.2 and $52.5 million, respectively and in the twelve months ended December 31, 2002 CONSOL Energy contributed net cash of $12.8 million to CNX Gas. We intend to satisfy our future working capital requirements and fund our future capital expenditures from cash from operations and, until we arrange for a separate credit facility, our intercompany credit arrangement with CONSOL Energy. CNX Gas has developed its own banking relationships, although for a brief period of time following the separation it continued to participate in CONSOL Energy’s cash management system under which cash generated by CNX Gas’ operations was received into CONSOL Energy’s cash accounts and CNX Gas’ payables were paid from CONSOL Energy’s cash accounts. These transactions were treated as intercompany loans.

CNX Gas and its 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 its 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 again guarantee the 7.875% Notes if CNX Gas in the future borrows money or otherwise incurs indebtedness by issuing notes, bonds, debentures or similar instruments to 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 again 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 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 noteholders, CONSOL Energy has determined that it cannot obtain, at this time, an amendment of the indenture on commercially acceptable terms. Therefore, CONSOL Energy will not formally solicit the 7.875% noteholders for the release and, consequently, we will remain guarantors of the 7.875% Notes.

General and administrative expenses contain fees of $6.3, $3.2 and $1.1 million for the twelve months ended December 31, 2004, 2003 and 2002, respectively, for certain accounting and administrative services

100

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.

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: $2.6 million from January 1, 2005 through June 30, 2005, $9.1 million in 2004, $9.3 million in 2003 and $10.7 million in 2002. CNX Gas captures and markets the gas from these wells and, therefore, benefits from this drilling activity, although it is not burdened with the cost to drill gob wells. CNX Gas is responsible for the costs incurred to gather and deliver the gob gas to market. All gob well drilling costs are borne by Consol Energy and only the collection and processing costs are reflected in CNX Gas’s historical financial statements and, as noted above under the caption “Master Cooperation and Safety Agreement—Wells and Capturing Gas”, our master cooperation and safety agreement with CONSOL Energy retains this cost structure after our separation from CONSOL Energy.

CONSOL Energy pays for metered power at certain mining operations in which we conduct our operations. We then reimburse CONSOL Energy for our allocable share of such metered power on a monthly basis, which amounts to approximately $150,000 per month.

CNX Gas employees participate in a non-contributory defined benefit pension plan administered by CONSOL Energy. Benefits for this plan are based primarily on years of service and employee’s pay near retirement. CNX Gas’ allocation of the pension expense under this plan was $1.4, $1.0 and $4.0 million for the twelve months ended December 31, 2004, 2003 and 2002, respectively. CONSOL Energy’s allocation of the expense for this plan is based on the percentage of CNX Gas’ active employee salary wages compared to the total active employee salary wages covered by the plan.

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 $337, $294 and $286 thousand for the twelve months ended December 31, 2004, 2003 and 2002, 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 $140, $152 and $158 thousand for the twelve months ended December 31, 2004, 2003 and 2002, 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.

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

•

101

•

CONSOL Energy is the guarantor of the agreement dated May 26, 2004 between CNX Gas Company and Equitable Energy, 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 our unpaid obligations related to this agreement, up to $10 million. The guaranty shall be a continuing guaranty and CONSOL Energy has the right to terminate the guaranty by providing Equitable Energy 30 days written notice.

•

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

•

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

In the future we may enter into additional material agreements and transactions with CONSOL Energy in addition to those previously described and the terms of such agreements will be subject to our charter’s conflict of interest provisions. See “Description of Capital Stock—Important Information Contained in the Certificate of Incorporation—Corporate Opportunities and Conflicts of Interest.”

CONSOL Energy’s Alternatives for Its Shares of Our Common Stock

As of the date of this prospectus, CONSOL Energy has no current plan or intention regarding the shares of our common stock it owns. After the date of this prospectus, CONSOL Energy may decide to dispose of its interest in CNX Gas, including through a sale of all or a portion of its shares of common stock to the public in a subsequent public offering or to a strategic investor, or through a pro rata distribution to its stockholders of the remaining shares of our common stock it owns in a distribution intended to be tax-free for U.S. federal income tax purposes to CONSOL Energy’s stockholders and to CONSOL Energy. Beneficial ownership of at least 80% of the total voting power and value of the outstanding common stock is required in order for CONSOL Energy to continue to include CNX Gas in its consolidated group for U.S. federal income tax purposes. In addition to satisfying certain other requirements, ownership of at least 80% of the total voting power and 80% of each class of nonvoting capital stock is required in order for CONSOL Energy to be able to effect a tax-free spin-off of CNX Gas. CONSOL Energy has indicated to CNX Gas that any decision by CONSOL Energy to reduce such beneficial ownership interest would be made in the future on the basis of all of the circumstances existing at such time, including the effect, if any, of any such reduction on CONSOL Energy, stock market conditions and other factors.

102

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

The following table sets forth information regarding the beneficial ownership of our common stock by:

•

our chief executive officer, other executive officers and directors;

•

all directors and executive officers as a group; and

•

each person known to us to own beneficially more than 5% of any class of our outstanding shares.

A person has beneficial ownership of shares if he has the power to vote or dispose of the shares. This power can be exclusive or shared, direct or indirect. In addition, a person is considered by SEC rules to beneficially own shares underlying options that are presently exercisable or will become exercisable within 60 days of the date of this prospectus. The shares listed in this table below under “Number of Shares Underlying Option/RSUs” include shares issuable upon the exercise of options that are presently exercisable or will become exercisable within 60 days of the date of this prospectus. Unless otherwise indicated in the footnotes to this table, each of the stockholders named in this table has sole voting and investment power with respect to the shares indicated as beneficially owned. Unless otherwise noted below, the business address for each of our directors, officers and 5% shareholders is 4000 Brownsville Road, South Park, PA 15129. Each of the persons below that may sell securities pursuant to this prospectus holds those positions with us as is set forth in the section titled “Management” in this prospectus.

As of December 15, 2005, there were 150,833,334 shares of our common stock outstanding. To calculate a stockholder’s percentage of beneficial ownership, we must include in the numerator and denominator those shares underlying options or restricted stock units that the stockholder is considered to beneficially own. Shares underlying options held by other stockholders, however, are disregarded in this calculation. Therefore, the denominator used in calculating beneficial ownership among our stockholders may differ.


	Shares of Common Stock Beneficially Owned Prior to Offering						Number of Shares of Common Stock that may be Sold in Offering
Name of Beneficial Owner	Number of Outstanding Shares		Number of Shares Underlying Options/RSUs	Total	Percent
Consolidation Coal Company(1)	122,896,667		—	122,896,667	81.5	%	—
Nicholas J. DeIuliis	6,000		—	6,000	*		6,000
Ronald E. Smith	56,250		—	56,250	*		56,250
Gary J. Bench	—		—	—	—		—
Stephen W. Johnson	—		—	—	—		—
J. Brett Harvey	15,625		—	15,625	*		15,625
James E. Altmeyer, Sr.	16,000	(2)	—	16,000	*		16,000
Philip W. Baxter	23,750	(3)	—	23,750	*		23,750
Raj K. Gupta	6,000	(4)	—	6,000	*		6,000
John R. Pipski	—		—	—	—		—
William J. Lyons	4,687		—	4,687	*		4,687
All Executive Officers and Directors as a group (10 persons)	128,312		—	128,312	*		—

*	Percentage of shares of common stock beneficially owned does not exceed one percent.

(1)	A wholly-owned subsidiary of CONSOL Energy.

(2)	Held by Mr. Altmeyer and his wife jointly.

(3)	Held by the Philip W. Baxter Trust, of which Mr. Baxter is a trustee.

(4)	Held by Mr. Gupta and his wife jointly.

103

SELLING STOCKHOLDERS

This prospectus covers shares sold in our recent private equity placement which was part of our separation. Some of the shares sold in the private equity placement were sold directly to “accredited investors” as defined by Rule 501(a) under the Securities Act pursuant to an exemption from registration provided in Regulation D, Rule 506 under Section 4(2) of the Securities Act. In addition, we sold shares to Friedman, Billings, Ramsey & Co., Inc., who acted as initial purchaser and sole placement agent in the offering. FBR sold the shares it purchased from us in transactions exempt from the registration requirements of the Securities Act to persons that it reasonably believed were “qualified institutional buyers,” as defined by Rule 144A under the Securities Act or to non-U.S. persons pursuant to Regulation S under the Securities Act. An affiliate of our former sole stockholder, the selling shareholders who purchased shares from us or FBR in the private equity placement and their transferees, pledgees, donees, assignees or successors, may from time to time offer and sell under this prospectus any or all of the shares listed opposite each of their names below.

The following table sets forth information about the number of shares owned by each selling stockholder that may be offered from time to time under this prospectus. Certain selling stockholders may be deemed to be “underwriters” as defined in the Securities Act. Any profits realized by the selling stockholder may be deemed to be underwriting commissions. Information as to our directors and officers who are selling stockholders is located in the table in the section titled “Security Ownership of Certain Beneficial Owners and Management.”

The table below has been prepared based upon the information furnished to us by the selling stockholders as of December 15, 2005. The selling stockholders identified below may have sold, transferred or otherwise disposed of some or all of their shares since the date on which the information in the following table is presented in transactions exempt from or not subject to the registration requirements of the Securities Act. Information concerning the selling stockholders may change from time to time and, if necessary, we will amend and/or supplement this prospectus accordingly. We cannot give an estimate as to the amount of shares of common stock that will be held by the selling stockholders upon termination of this offering because the selling stockholders may offer some or all of their common stock under the offering contemplated by this prospectus. The total amount of shares that may be sold hereunder will not exceed the number of shares offered hereby. Please read “Plan of Distribution.”

We have been advised that as noted below in the footnotes to the table, · of the selling stockholders are broker-dealers and certain of the selling stockholders are affiliates of broker-dealers. We have been advised that each of such selling stockholders purchased our common stock in the ordinary course of business, not for resale, and that none of such selling stockholders had, at the time of purchase, any agreements or understandings, directly or indirectly, with any person to distribute the common stock. If the shares are to be sold by transferees of the selling stockholders under this prospectus, we must file a post-effective amendment to the registration statement that includes this prospectus or a prospectus supplement, amending the list of selling stockholders to include the transferee as a selling stockholder. Upon being notified by a selling stockholder that it intends to use an agent or principal to sell their shares, a post-effective amendment to the registration statement that includes this prospectus will be filed, naming the agent or principal as an underwriter and disclosing the compensation arrangement. All selling stockholders are subject to Rule 105 of Regulation M and are precluded from engaging in any short selling activities prior to effectiveness and for as long as they are participants in the offering.

Except as noted below, to our knowledge, none of the selling stockholders has, or has had within the past three years, any position, office or other material relationship with us or any of our predecessors or affiliates, other than their ownership of shares described below.

104


	Shares of Common Stock Beneficially Owned Prior to Offering				Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
2003 Houston Energy Partners	121,000		*	%	121,000
3 Notch Capital Partners, L.P.	50,275		*		50,275
Adar Investment Fund	300,000		*		300,000
Advisory Research Energy Fund LP	188,300		*		188,300
Affron, Charles & Mirella ST/WROS	2,000		*		2,000
AG Arb Partners, LP†	26,750		*		26,750
AG CNG Fund, LP†	13,750		*		13,750
AG MM, LP†	9,250		*		9,250
AG Princess, LP†	7,000		*		7,000
AG Super Fund International Partners, LP†	28,000		*		28,000
AG Super Fund, LP†	88,750		*		88,750
AIM Capital Development Fund†	211,200		*		211,200
AIM Dynamics Fund†	332,300		*		332,300
AIM Midcap Growth Fund†	31,000		*		31,000
AIM VI Capital Development Fund†	31,900		*		31,900
AIM VI Dynamics Fund†	18,600		*		18,600
Alexander, Leslie	100,000		*		100,000
Alexandra Global Master Fund Ltd.	226,700		*		226,700
All-Cap Energy Hedge Fund LLC	4,600	(46)	*		4,600
Allied Funding Inc.	10,000		*		10,000
Alonso, Steven	5,000		*		5,000
Alpha US Sub Fund I LLC	10,629		*		10,629
Altmeyer, James E. Jr. & Jocelyn Coles	2,000		*		2,000
Amaranth LLC†	193,300	(1)	*		193,300
Amber Funds Limited	100,000		*		100,000
American Funds Insurance Series Asset Allocation Fund	125,000	(2)	*		125,000
Annie E. Casey Foundation	2,700	(47)	*		2,700
Ariella Ben-Dov Trust	25,000		*		25,000
Aron, Millicent	510	(3)	*		510
Atlas Capital (QP) LP	89,170		*		89,170
Atlas Capital Master Fund Ltd.	157,489		*		157,489
Atlas Master Fund Ltd.	222,500		*		222,500
Avenue Event Driven Master Fund	260,200		*		260,200
Axia Offshore Partners Ltd.	15,892		*		15,892
Axia Partners LP	20,011		*		20,011
Axia Partners Qualified LP	85,968		*		85,968
Barrish, Jack	12,000		*		12,000
Basso Fund Ltd.	2,500		*		2,500
Basso Multi-Strategy Holding Fund Ltd.	7,500		*		7,500
Bay Pond Investors (Bermuda) LP	35,600	(4)	*		35,600
Bay Pond Partners LP	113,000	(4)	*		113,000
BBT Fund, LP	132,750		*		132,750
Bear Stearns SEC Corp Cust FBO J. Steven Emerson IRA R/O II	115,400		*		115,400
Bermuda Partners LP	22,470		*		22,470
Beta Equities, Inc.†	420,000		*		420,000
Blackrock All-Cap Global Resources Portfolio	9,600	(46)	*		9,600

105


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
Blackrock Asset Allocation Portfolio (Mid Cap Growth)	3,200	(46)	*	3,200
Blackrock Asset Allocation Portfolio — Mid Cap Value	4,300	(46)	*	4,300
Blackrock Aurora Portfolio	591,100	(46)	*	591,100
Blackrock Global Energy & Resources Trust	66,000	(47)	*	66,000
Blackrock Mid Cap Value Equity Portfolio	62,300	(46)	*	62,300
Blackrock Mid-Cap Growth Equity Portfolio	36,700	(46)	*	36,700
Blackrock Small Cap Value Equity Portfolio	28,000	(46)	*	28,000
Blackrock US Opportunities Portfolio	7,600	(46)	*	7,600
Boebinger, Dean Lovell	400		*	400
Boston Partners Asset Management, LLC†	352,700	(5)	*	352,700
Boston Provident Partners LP	90,700		*	90,700
BP Institutional Partners LP	5,900		*	5,900
Brady Retirement Fund LP	5,800		*	5,800
Brookside Capital Partners Fund LP	250,000		*	250,000
Calm Waters Partnership	25,000	(48)	*	25,000
Canyon Balanced Equity Master Fund Ltd.†	79,130		*	79,130
Canyon Capital Value Realization Fund, LP†	158,260		*	158,260
Canyon Value Realization Fund (Cayman) Ltd.†	532,180		*	532,180
Canyon Value Realization MAC 18 Ltd. (RMF)†	7,910		*	7,910
Capital Guardian U.S. Small Capitalization Master Fund†	139,100		*	139,100
Capital Guardian U.S. Small Capitalization Master Fund (Private Placement Eligible)†	3,000		*	3,000
Capital International US Small Cap Fund†	2,300		*	2,300
Castlerigg Master Investments Ltd.	50,000	(6)	*	50,000
Castlerock Fund Ltd.	85,380		*	85,380
CastleRock Partners II LP	11,520		*	11,520
Castlerock Partners, L.P.	138,030		*	138,030
Catalyst Fund Offshore Ltd.	1,995		*	1,995
Ceisel, Charles Barton	2,000		*	2,000
Central States Southeast and Southwest Areas Pension Fund†	71,820	(3)	*	71,820
Chamberlin Investments Ltd.	6,270		*	6,270
Chiles Foundation	2,400	(6)	*	2,400
Chimermine, Lawrence	1,000		*	1,000
Citi Canyon Ltd.†	7,910		*	7,910
Coleman, John M. & Patricia D.	7,500		*	7,500
Coleman, Sean	3,500		*	3,500
Concentrated Alpha Partners, LP	78,750		*	78,750
Continental Casualty Company†	200,000		*	200,000
Copeland, Darryl W. Jr.	9,375		*	9,375
Crestview Capital Master LLC†	10,000		*	10,000
Cutchogue Point AP LP	250,000		*	250,000
Dascoli, James C.†	100		*	100

106


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
DB Zwirn Special Opportunities Fund Ltd.	35,250	(7)	*	35,250
DB Zwirn Special Opportunities Fund, LP	180,255	(8)	*	180,255
Deephaven Distressed Opportunities Trading, Ltd.	267,433		*	267,433
Deephaven Event Trading Ltd.	522,454		*	522,454
Edenworld International Ltd.	3,229		*	3,229
Edward Fox IRA	7,500		*	7,500
Edwin McGough IRA R/O	830	(3)	*	830
Elliott J. Horowitz TTEE for the Elliott J. Horowitz 89 dated 11/1/89	6,300		*	6,300
Eton Park Fund, L.P.	350,000		*	350,000
Eton Park Master Fund, Ltd.	650,000		*	650,000
Evelyn Berry Spousal IRA R/O	1,315	(3)	*	1,315
Ewing, Frank	10,000		*	10,000
Ewing, Judith H.	5,000		*	5,000
Excelsior Value & Restructuring	625,000		*	625,000
Far West Capital Partners LP	167,000		*	167,000
Farvane Limited	876		*	876
Feinberg, Richard	25,107		*	25,107
Ferial Polhill LLC	5,800		*	5,800
Fiddler, Thomas J.	6,000		*	6,000
Fidelity Advisor Balanced Fund†	11,700	(9)	*	11,700
Fidelity Advisors New Insights Fund†	17,900	(9)	*	17,900
Fidelity Contrafund†	410,600	(9)	*	410,600
Fidelity Puritain Trust: Fidelity Balanced Fund†	115,000	(9)	*	115,000
Fidelity Variable Insurance Products Fund II: Contrafund†	115,300	(9)	*	115,300
Fidelity Variable Insurance Products Fund III: Balanced Fund†	2,600	(9)	*	2,600
Fingerhut, Bert	12,500		*	12,500
First Eagle U.S. Value Fund†	50,000		*	50,000
Fleet Maritime Inc.	22,246		*	22,246
Frankel, Benjamin & Linda	2,500		*	2,500
Franklin Mutual Recovery Fund	133,000	(10)	*	133,000
Frederic H. Lindeberg Money Purchase Pension Plan	2,000		*	2,000
Front Point Energy Horizons Fund LP	125,000	(11)	*	125,000
Front Point Utility and Energy Fund LP	125,000	(12)	*	125,000
Fundamental Investors Inc.	575,000		*	575,000
Gallatin, Ronald L.	25,000		*	25,000
Galleon Admiral’s Offshore Ltd.	100,000		*	100,000
Galleon Captain’s Offshore Ltd.	80,000		*	80,000
Galleon Captain’s Partners LP	20,000		*	20,000
GAM Arbitrage Investments Inc.†	50,000		*	50,000
Gardner Lewis Fund LP	78,400		*	78,400
Gartmore Nationwide Small Cap Fund†	11,000		*	11,000
Gas Partners LP	3,000		*	3,000
Geary Partners LP	19,500		*	19,500

107


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
George Weiss Associates Inc. Profit Sharing Plan†	225,000		*	225,000
GMF Global Natural Resources Fund†	9,000		*	9,000
Goldman Sachs Asset Management Foundation†	2,385	(3)	*	2,385
Goldman, Sachs & Co.	625,000		*	625,000
Goldsmith Family Foundation Inc.	6,900		*	6,900
Goldsmith Family Investments LLC	5,100		*	5,100
Goldstein, Robert B. & Candy K., Tenants-in-Common	2,800		*	2,800
Golush, David	2,000		*	2,000
Golzar, Fardin	3,000		*	3,000
Gracie Capital International II, Ltd.	8,942		*	8,942
Gracie Capital International Ltd.	50,269		*	50,269
Gracie Capital LP	90,789		*	90,789
Grech, James Charles	1,562	(13)	*	1,562
Greenwich Street Series Capital and Income Fund	3,900		*	3,900
Gruber & McBain International	11,000	(14)	*	11,000
Guggenheim Portfolio Company XIX LLC	35,000		*	35,000
Haddad Family Trust	10,000		*	10,000
Hammond, John F. & Wiegand, Christy C.	12,500	(15)	*	12,500
Harbour Holdings Ltd.	5,000		*	5,000
Hare & Co. F/B/O JHIC Vermont—Hallmark Cards Inc.†	5,435		*	5,435
Hare & Co. F/B/O John Hancock Balanced Fund†	39,880		*	39,880
Hare & Co. F/B/O John Hancock Large Cap Equity Fund†	245,095		*	245,095
Hare & Co. F/B/O John Hancock Large Cap Intrinsic Value Fund†	2,415		*	2,415
Hare & Co. F/B/O John Hancock Small Cap Intrinsic Value Fund†	1,610		*	1,610
Hare & Co. F/B/O John Hancock Small Cap Opportunity Account†	975		*	975
Hare & Co. F/B/O John Hancock TOH1—Large Cap Equity Fund 4C†	4,590		*	4,590
Hartford Series Fund NC—Hartford Midcap HLS Fund	314,900	(4)	*	314,900
HCM/Z Special Opportunities LLC†	13,395	(16)	*	13,395
HFR HE Beryllium Fund	32,800		*	32,800
HFR HE Financial II Master Trust	14,900		*	14,900
HFR HE Systematic Master Trust	42,600	(17)	*	42,600
HG Holdings II Ltd.	76,875	(18)	*	76,875
HG Holdings Ltd.	363,750	(18)	*	363,750
Hicks, Caroline	7,500		*	7,500
High, Joanne A. & Roger W.	900		*	900
Highbridge Event Driven/Relative Value Fund LP	34,615		*	34,615

108


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
Highbridge Event Driven/Relative Value Fund Ltd.	240,385		*	240,385
Highbridge International LLC	225,000		*	225,000
Hirsch, Catherine	1,000		*	1,000
Hirschorn, Martin	45,000		*	45,000
Hoffman, Thomas P. & Karen J.	937	(19)	*	937
Holladay, Wallace F. Jr.	3,500		*	3,500
Holt, Jack A.	14,062	(20)	*	14,062
Howard C. Bluver	1,500		*	1,500
Howard, Jeffrey H. & Brenda H.	2,800		*	2,800
HSBC Guyerzeller Trust Co as Trustee of The Green Forest Trust	4,251		*	4,251
Hughes, Thomas	2,000		*	2,000
Hunter Global Investors Fund I L.P.	178,125	(18)	*	178,125
Hunter Global Investors Fund II L.P.	6,250	(18)	*	6,250
Huthwaite, Daniel & Constance	2,800		*	2,800
IL Hedge Investments LLC	15,000		*	15,000
Institutional Benchmarks Master Fund Ltd.†	7,910		*	7,910
Investors of America, Limited Partnership†	215,000		*	215,000
Ironman Energy Capital LP	20,000		*	20,000
Irwin, Hale	3,000		*	3,000
ITT Hartford Mutual Fund Inc.—The Hartford Mid Cap	345,200	(4)	*	345,200
IVY-MA Holdings Co LLC	41,400	(21)	*	41,400
JAM Investments, LLC	2,800		*	2,800
Jana Master Fund Ltd.	273,900		*	273,900
JCK Partners Opportunities Fund Ltd.	1,600	(22)	*	1,600
Jennison Natural Resources Fund Inc.†	96,200	(23)	*	96,200
Jennison Small Company Fund Inc.†	59,800	(23)	*	59,800
Jennison Utility Fund†	404,200	(23)	*	404,200
John A. Hartford Foundation Inc.	13,900	(3)	*	13,900
Johnson Revocable Living Trust dtd 5/14/98	9,000		*	9,000
Johnson Value Partners LP	5,000	(24)	*	5,000
Jon D. & Linda N. Gruber Trust	15,000		*	15,000
Kantarian, Harry K.	10,000		*	10,000
Kayne Anderson Energy Infrastructure Fund LP†	12,700	(25)	*	12,700
Kayne Anderson Energy Total Return Fund†	143,100	(25)	*	143,100
Kayne Anderson Midstream Energy Fund, Ltd.†	21,100	(25)	*	21,100
Kayne Anderson MLP Fund LP†	93,100	(25)	*	93,100
Kettler, Robert C.	7,500		*	7,500
King Investment Advisors, Inc.	7,000		*	7,000
King, Roger E., Separate Property	30,000		*	30,000
Kings Road Investments Ltd.	325,000	(26)	*	325,000
Kollins, John A. & Cryan, Mary Ann	1,250		*	1,250
L.H. Rich Companies	5,000		*	5,000
Lagunitas Partners LP	49,000	(27)	*	49,000
Lenfest, Brook J.	62,500		*	62,500

109


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
Leonard Weinglass, Trustee of the Revocable Trust U/A dtd 6/17/89	4,800		*	4,800
Liebro Partners LLC	2,000		*	2,000
Lifespan Corporation	1,400	(47)	*	1,400
Lilly, Peter B. & Brenda E.	12,500	(28)	*	12,500
Lippman, Christopher Shaw	6,250		*	6,250
Locke, James & Susan Tenants by their Entirety	15,500		*	15,500
Lubert, Ira	45,000		*	45,000
Luterman, D. William	6,250		*	6,250
M J Murdock Charitable Trust	48,500		*	48,500
M.A. Deep Event, Ltd.	53,613		*	53,613
Mason Capital Ltd	20,700		*	20,700
Mavian Inc	580	(3)	*	580
May, Matthew	2,800		*	2,800
May, Richard A. & Dana D.	2,800		*	2,800
McCaffrey, James J. & Terry Ann	2,187		*	2,187
McCleary, Dale L.	6,000		*	6,000
McCleary, Ryan C.	4,000		*	4,000
McCorkindale, Douglas H.	7,500		*	7,500
McFarland, Joan O	600		*	600
Meijer Inc. Pension Plan	12,360	(3)	*	12,360
MetLife Post Retirement Benefits (PRB)	1,300	(47)	*	1,300
Metropolitan Series Fund, Inc.—Small Cap Value Fund	212,200	(46)	*	212,200
Metropolitan Series Fund, Inc.—Aggressive Growth Fund	77,500	(46)	*	77,500
Miami University Endowment	2,050		*	2,050
Miami University Foundation	2,610		*	2,610
Millennium Partners LP†	200,000	(29)	*	200,000
Mills, Alvin Jackson Jr.	3,000		*	3,000
Ministers & Missionaries Benefit Board of American Baptist Churches	9,900	(46)	*	9,900
MM & B Holdings	15,000		*	15,000
Modern Capital Fund LLC	25,000		*	25,000
Moeser, James IRA Rollover	2,800		*	2,800
Morgan, Claude D.	1,000	(30)	*	1,000
Mulberry Master Fund Ltd	5,000		*	5,000
Mutual Beacon Fund)	443,000	(10)	*	443,000
Mutual Beacon Fund (Canada)	49,000	(10)	*	49,000
Mutual of America Investment Corporation Aggressive Equity Fund†	67,070		*	67,070
Mutual of America Institutional Funds, Inc. Aggressive Equity Fund†	3,520		*	3,520
Mutual of America Investment Corporation Mid Cap Value Fund†	2,360		*	2,360
Mutual of America Investment Corporation All America Fund†	17,650		*	17,650

110


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
Mutual of America Institutional Funds, Inc. All America Funds†	2,180		*	2,180
Mutual of America Investment Corporation Small Cap Value Fund†	7,220		*	7,220
National Grid USA	6,000	(46)	*	6,000
Natural Resources Portfolio of the Prudential Series Fund, Inc.†	89,800	(23)	*	89,800
Neal, Jeffrey Todd	11,188		*	11,188
Neese Family Equity Investments Ltd	2,645		*	2,645
Niagara Mohawk Power	4,500	(46)	*	4,500
Nicholson, Nicholas G and Charlotte A	1,250		*	1,250
Nusrala, Edward J. IRA	10,000		*	10,000
Nutmeg Partners, LP†	16,000		*	16,000
Oz Master Fund, Ltd.	611,133		*	611,133
Panther Partners LLC	40,000		*	40,000
Park West Investors LLC	90,556		*	90,556
Park West Partners International LTD	20,344		*	20,344
Pennsylvania Municipal Retirement System	14,900		*	14,900
Perennial Investors LLC	145,000		*	145,000
Peterson Investment Trust	40,000		*	40,000
PHS Bay Colony Fund LP†	7,000		*	7,000
PHS Patriot Fund, LP†	3,500		*	3,500
PIMCO Flex-Cap Value	50,000	(31)	*	50,000
Pioneer Funds US Small Companies (LUX)	35,300	(32)	*	35,300
Pioneer Small Cap Value Fund	192,100	(32)	*	192,100
Pioneer Small Cap Value II VCT Portfolio	11,900	(32)	*	11,900
Pioneer Small Cap Value VCT Portfolio	10,700	(32)	*	10,700
Pohanka Oldsmobile Inc.	40,000		*	40,000
Pohanka Virginia Properties	55,000		*	55,000
Pohanka, Geoffrey	50,000		*	50,000
Polhill, Ferial	3,800		*	3,800
Precept Capital Master Fund GP	22,000		*	22,000
Presidio Partners	24,700		*	24,700
Prism Offshore Fund Ltd.	21,000	(33)	*	21,000
Prism Partners LP	12,000	(33)	*	12,000
Prism Partners QP LP	7,000	(33)	*	7,000
Ralph & Debbie Pastore Pension Plan TTEES	4,000		*	4,000
Raytheon Combined DB/DC Master Trust	3,000	(47)	*	3,000
Raytheon Master Pension Trust	8,200	(47)	*	8,200
Raytheon Master Pension Trust #2	2,000	(47)	*	2,000
Reilly, John D.	6,250		*	6,250
Richard S. Bodman Revocable Trust dtd 9/1/1998 TTEE	3,500		*	3,500
Richey, P. Jerome & Cynthia K.	2,000	(34)	*	2,000
RL Capital Partners†	500		*	500
RNR II LP	150,600		*	150,600
RNR III (Offshore) Ltd.	21,200		*	21,200
RNR III LP	45,400		*	45,400
Rockbay Capital Fund, LLC	4,400		*	4,400

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	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
Rockbay Capital Institutional Fund, LLC	68,909		*	68,909
Rockbay Capital Offshore Fund, Ltd.	201,691		*	201,691
Rothstein, Allan P.	40,000		*	40,000
Rothstein, Steven	20,000		*	20,000
Royal Bank of Canada	225,000		*	225,000
Salomon Brothers Capital & Income Fund	58,100		*	58,100
Saratoga Capital LLC	25,000		*	25,000
Scheller, Walter J.	6,250		*	6,250
Schiro, Robert G.	60,000		*	60,000
Scudder Dreman Small Cap Fund	188,100		*	188,100
SF Capital Partners Ltd.	100,000		*	100,000
Smith Barney Capital & Income Fund	135,500		*	135,500
South Ferry Building Company LP	137,000		*	137,000
Spring Street Partners LP	10,000		*	10,000
SRI Fund LP	13,500		*	13,500
St. Louis Archdiocesan Fund	5,100	(46)	*	5,100
State Farm Variable Product-Small Cap Equity†	5,600		*	5,600
Steuart Investment Company	19,000	(35)	*	19,000
Sucaba CRUT Partners	32,500		*	32,500
Sucaba Partners	97,500		*	97,500
Sun Capital Advisors Trust(2)	11,300		*	11,300
Susan J. Pohanka Declaration of Trust	30,000		*	30,000
Susan Pohanka Schantz Grantor Retained Annuity Trust	17,000		*	17,000
SVS Asset Management LLC	1,575	(3)	*	1,575
SVS Dreman Small Cap Value Portfolio	111,900		*	111,900
Syme, J. Anthony & Phyllis K.	1,500		*	1,500
Szymanski, Joseph	5,300		*	5,300
T. Ferguson Locke IRA†	6,250		*	6,250
Tamar Ben-Dov Trust	25,000		*	25,000
Taube Family Trust	725	(3)	*	725
Tetra Capital Partners LP	10,000	(36)	*	10,000
The Northwestern Mutual Life Insurance Company†	500,000	(37)	*	500,000
The WHX Pension Plan Trust	25,000		*	25,000
Theil, John D.	1,500		*	1,500
Third Avenue Trust on behalf of Third Avenue Small Cap Value Fund Series†	405,000		*	405,000
Thomas D. Hogan IRA R/O	480		*	480
Tiger Veda Global	100,000		*	100,000
Touradji Global Resources Master Fund Ltd	691,300		*	691,300
Toro, Andres E.	12,500		*	12,500
Treaty Oak Ironwood	9,918		*	9,918
Treaty Oak Master	8,423		*	8,423
Tribeca Global Investments Ltd.†	645,000		*	645,000
TW Partners Ltd.	8,500		*	8,500
Twin Offshore Ltd	150		*	150
Twin Securities LP	350		*	350

112


	Shares of Common Stock Beneficially Owned Prior to Offering			Number of Shares of Common Stock that may be sold in Offering
Name of Selling Stockholder	Number of Outstanding Shares		Percent
United Capital Management, Inc.	25,000		*	25,000
University of Cincinnati Foundation	3,900	(46)	*	3,900
University of Mississippi Endowment	1,425	(13)	*	1,425
University of Mississippi Foundation	6,840	(13)	*	6,840
University of Mississippi Medical Center	1,365	(13)	*	1,365
VentureSim Inc.	3,000	(38)	*	3,000
Vestal Venture Capital	100,000		*	100,000
Walker Smith Capital (QP) LP	31,500	(39)	*	31,500
Walker Smith Capital LP	5,600	(39)	*	5,600
Walker Smith International Fund Ltd.	44,200	(39)	*	44,200
Walsh, Terence X. & Altmeyer, V. Cameron	10,000		*	10,000
Wasatch Heritage Growth Fund	78,875	(40)	*	78,875
Wasatch Small Cap Value Fund	329,265	(40)	*	329,265
Western Reserve Master Fund, LP	40,000		*	40,000
Westfield Life Sciences Fund II LP	266,000		*	266,000
Westfield Life Sciences Fund LP	49,000		*	49,000
Wexford Catalyst Investors LLC	135,000	(41)	*	135,000
Wexford Spectrum Investors LLC	165,000	(41)	*	165,000
Wiegers & Co. LLC	7,500		*	7,500
William A. Hazel Revocable Trust	7,500		*	7,500
William K. Warren Foundation	40,000	(42)	*	40,000
Williams, Joseph Theodore	5,000		*	5,000
Wolfson, Aaron	10,000		*	10,000
Wolfson, Abraham	5,000		*	5,000
Wood & Co.	150,000		*	150,000
Wooster Capital LP	149,000	(21)	*	149,000
Wooster Offshore Fund	384,600	(21)	*	384,600
WS Opportunity Fund (QP) LP	5,400	(43)	*	5,400
WS Opportunity Fund International Ltd	7,800	(43)	*	7,800
WS Opportunity Fund LP	5,500	(43)	*	5,500
Y & H Soda Foundation	5,670		*	5,670
York Capital Management LP	33,250		*	33,250
York Credit Opportunities Fund, LP	30,800		*	30,800
York Global Value Partners, LP	43,100		*	43,100
York Investment Limited.	142,850		*	142,850
York, John	15,937		*	15,937
Zajdel, Daniel J.	25,000	(44)	*	25,000
Zander Capital Management LLC	50,000		*	50,000
Ziff Asset Management	300,000	(45)	*	300,000
Zimmerman, Yale	2,000		*	2,000
Zirkin, Harold	5,000		*	5,000

*Percentage of shares of common stock beneficially owned does not exceed one percent

†	Broker-dealer affiliate.

††	Broker-dealer

1.	Amaranth Advisors L.L.C., the Trading Advisor for Amaranth LLC, exercises dispositive powers with respect to these shares and as such may be deemed to have beneficial ownership of such shares. Amaranth

113

Advisors L.L.C. has designated authorized signatories who will sign on behalf of Amaranth LLC, the selling stockholder. Nicholas M. Maounis is the managing member of Amaranth Advisors L.L.C.

2.	The selling stockholder shares voting and dispositive power with Capital Research and Management Company.

Wasatch Advisors, Inc. is the investment adviser to Wasatch Funds, Inc., a registered investment company comprised of a series of funds under the Investment Company Act of 1940, and to a number of private separate client accounts which are the beneficial owners of the Company’s stock. The funds and private accounts hold the Company’s stock solely for investment purposes, with no intent to control the business or affairs of the Company. John Mazanec or another designee of Wasatch Advisors, Inc. has voting and investment power over the shares that this selling stockholder beneficially owns. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholders.

4.	Wellington Management Company, LLP (“Wellington”) is an investment adviser registered under the Investment Advisers Act of 1940, as amended. Wellington, in such capacity, is deemed to share beneficial ownership over the shares held by its client’s accounts.

5.	BPAM has sole voting and investment power over shares of common stock of the Company acting in its capacity as investment adviser on behalf of various of its accounts, none of which is a natural person.

Sandell Asset Management Corp. (“SAMC”), is the investment manager of Castlerigg Master Investments Ltd. (“Master”). Thomas Sandell is the controlling person of SAMC and may be deemed to share beneficial ownership of the shares beneficially owned by Master. Castlerigg International Ltd. (“Castlerigg International”) is the controlling shareholder of Castlerigg International Holdings Limited (“Holdings”). Holdings is the controlling shareholder of Master. Each of Holdings and Castlerigg International may be deemed to share beneficial ownership of the shares beneficially owned by Castlerigg Master Investments. SAMC, Mr. Sandell, Holdings and Castlerigg International each disclaims beneficial ownership of the securities with respect to which indirect beneficial ownership is described.

D.B. Zwirn & Co., L.P. is the trading manager of D.B. Zwirn Special Opportunities Fund, Ltd. Daniel B. Zwirn is the managing member of and thereby controls Zwirn Holdings, LLC, which in turn is the managing member of and thereby controls DBZ GP, LLC, which in turn is the general partner of and thereby controls D.B. Zwirn & Co., L.P. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholder.

D. B. Zwirn Partners, LLC is the General Partner of D.B. Zwirn Special Opportunities Fund, L.P. Daniel B. Zwirn is the managing member of and thereby controls Zwirn Holdings, LLC, which in turn is the managing member of and thereby controls D.B. Zwirn Partners, LLC. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholder.

The entity is a registered investment fund (the “Fund”) advised by Fidelity Management & Research Company (“FMR Co.”), a registered investment adviser under the Investment Advisers Act of 1940, as amended. FMR Co., 82 Devonshire Street, Boston, Massachusetts 02109, a wholly-owned subsidiary of FMR Corp. and an investment adviser registered under Section 203 of the Investment Advisers Act of 1940, is the beneficial owner of 673,100 shares of the Common Stock outstanding of the Company as a result of acting as investment adviser to various investment companies registered under Section 8 of the Investment Company Act of 1940. Edward C. Johnson 3d, FMR Corp., through its control of FMR Co., and the Fund each has sole power to dispose of the securities owned by the Fund. Neither FMR Corp. nor Edward C. Johnson 3d, Chairman of FMR Corp., has the sole power to vote or direct the voting of the shares owned directly by the Fund, which power resides with the Fund’s Board of Trustees.

10.	Pursuant to an investment advisory contract with Franklin Mutual Advisers, LLC (“FMA”), FMA has sole investing and voting control over the securities beneficially owned by these selling stockholders. FMA disclaims beneficial ownership of such securities.

11.	FrontPoint Energy Horizons Fund GP, LLC is the general partner of FrontPoint Energy Horizons Fund, L.P. FrontPoint Partners LLC is the managing member of FrontPoint Energy Horizons Fund GP, LLC and as

114

such has voting and dispositive power over the securities held by the fund. Philip Duff, W. Gillespie Caffray and Paul Ghaffari are members of the Board of Managers of FrontPoint Partners LLC and are members of its Management Committee. Messrs. Duff, Caffray and Ghaffari and FrontPoint Partners LLC and FrontPoint Energy Horizons Fund GP, LLC each disclaim beneficial ownership of the securities held by the fund except for their pecuniary interest therein.

12.

FrontPoint Utility and Energy Fund GP, LLC is the general partner of FrontPoint Utility and Energy Fund, L.P. FrontPoint Partners LLC is the managing member of FrontPoint Utility and Energy Fund GP, LLC and as such has voting and dispositive power over the securities held by the fund. Philip Duff, W. Gillespie Caffray and Paul Ghaffari are members of the Board of Managers of FrontPoint Partners LLC and are members of its Management Committee. Messrs. Duff, Caffray and Ghaffari and FrontPoint Partners LLC and FrontPoint Utility and Energy Fund GP, LLC each disclaim beneficial ownership of the securities held by the fund except for their pecuniary interest therein.

12.	Castlerock Partners has the power to vote and dispose of the securities held by this selling stockholder.

13.	Mr. Grech has served as the Vice President—Energy from January 1, 2003 to February 20, 2004, the Vice President—Appalachian Gas and Energy Marketing from February 20, 2004 to August 15, 2005 and the Senior Vice President—Marketing of CONSOL Energy since August 15, 2005.

14.

Gruber & McBaine Cap Mgmt. the investment advisor has voting and dispositive power of security. As managers of Gruber & McBaine Cap Mgmt., Jon D. Gruber and Linda W. Gruber oversee investment activity. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholder.

15.	Mr. Hammond has served as Senior Attorney of CONSOL Energy Inc. since June 1, 2004.

16.

D.B. Zwirn & Co., L.P. is the trading manager of HCM/Z Special Opportunities LLC. Daniel B. Zwirn is the managing member of and thereby controls Zwirn Holdings, LLC, which in turn is the managing member of and thereby controls DBZ GP, LLC, which in turn is the general partner of and thereby controls D.B. Zwirn & Co., L.P. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholder.

18.

Duke Buchan III controls Hunter Global Investors L.P., the investment manager of this selling stockholder, and has sole voting and investment power over the shares held by this entity. The foregoing should not be construed in and of itself as an admission by Mr. Buchan of beneficial ownership of the shares.

19.	Mr. Hoffman has served as the Vice President—Investor and Public Relations from April 1, 2002 to August 15, 2005 and the Vice President External Affairs of CONSOL Energy Inc. since August 15, 2005.

20.	Mr. Holt has served as Vice President—Safety, H.R. and Organizational Development from April 1, 2002 to January 1, 2004, the Vice President Safety and H.R. from January 1, 2004 to November 1, 2004 and the Senior Vice President—Safety of CONSOL Energy Inc. since November 1, 2004.

21.	David Steinhardt holds the sole power to vote and dispose of the securities held by this selling stockholder.

22.	Sole voting and dispositive power of the securities held by the selling stockholder is held by JCK Partners, L.P. as investment manager and therefore, JCK Partners, L.P. may be deemed to be a beneficial owner of such securities.

23.

Jennison Associates LLC serves as investment advisor with the power to direct the vote and to dispose of all the securities held by these selling stockholders listed above, and may be deemed to be the indirect beneficial owner of such securities. Jennison Associates LLC expressly disclaims beneficial ownership of such shares.

24.	Steven R. Johnson holds sole voting and dispositive power over the securities held by this selling stockholder.

115

25.	Voting and dispositive power of these shares is shared with Richard A. Kayne as controlling party of the selling stockholder.

26.

Kings Road Investments Ltd. (“Kings Road”) is a wholly-owned subsidiary of Polygon Global Opportunities Master Fund (“Master Fund”). Polygon Investment Partners LLP, Polygon Investment Partners LP and Polygon Investments Ltd. (the “Investment Managers”), the Master Fund, Alexander Jackson, Reade Griffith and Paddy Dear share voting and dispositive power of the securities held by Kings Road. Alexander Jackson, Reade Griffith and Paddy Dear control the Investment Managers. The Investment Managers, Alexander Jackson, Reade Griffith and Paddy Dear disclaim beneficial ownership of the securities held by Kings Road.

27.

Gruber & McBaine Cap Mgmt. as the general partner have voting and dispositive power of security. As Gruber & McBaine Cap Mgmt. managers, Jon D. Gruber and J. Patterson McBaine oversee investment activity. These persons may therefore be deemed to have beneficial ownership over the securities held by the selling stockholder.

28.	Mr. Lilly has served as Chief Operating Officer of CONSOL Energy Inc. since October 2002.

29.

Millennium Management, L.L.C., a Delaware limited liability company, is the managing partner of Millennium Partners, L.P., a Cayman Islands exempted limited partnership, and consequently may be deemed to have voting control and investment discretion over securities owned by Millennium Partners, L.P. Israel A. Englander is the managing member of Millennium Management, L.L.C. As a result, Mr. Englander may be deemed to be the beneficial owner of any shares deemed to be beneficially owned by Millennium Management, L.L.C. The foregoing should not be construed in and of itself as an admission by either of Millennium Management, L.L.C. or Mr. Englander as to beneficial ownership of the shares of the Company’s common stock owned by Millennium Partners, L.P.

30.	Mr. Morgan served as Vice President—Gas Operations of CONSOL Energy Inc. from April 1, 2002 to August 15, 2005 when he became the Vice President—Gas Operations of CNX Gas Corporation.

31.

This selling stockholder has delegated full authority to Nicholas-Applegate Capital Management as investment adviser over these securities, including full voting and dispositive power. Nicholas-Applegate Capital Management is a registered investment adviser under the Investment Adviser’s Act of 1940.

32.

Pioneer Investment Management, Inc. (“PIM”), the selling stockholder’s investment advisor, has or shares voting and dispositive power with respect to these securities. PIM is a privately held company the sole shareholder of which is Pioneer Investment Management USA Inc. (“PIMUSA”). The sole shareholder of PIMUSA is a private Italian company called Pioneer Global Asset Management S.p.A. (“PGAM”). The parent company of PGAM is UniCredito Italiano S.p.A., a publicly traded Italian bank.

33.	Charles Jobson holds voting and dispositive power over the securities held by this selling stockholder in his capacity as Managing Member of Delta Partners, LLC and Delta Advisors, LLC.

34.	Mr. Richey has served as Vice President and General Counsel of CONSOL Energy Inc. since February 2005.

35.	Carter Steuart and Mike Goheen hold sole voting and dispositive power over the securities held by this selling stockholder.

36.	Tim O’ Toole and Charles Jobson hold voting and dispositive power over the securities held by this selling stockholder as Managing Members of Tetra Capital Management, LLC.

37.

Northwestern Investment Management Company, LLC (“NIMC”) is one of the investment advisers to Northwestern Mutual and is the investment adviser for Northwestern Mutual with respect to the securities listed in this prospectus. NIMC therefore may be deemed to be an indirect beneficial owner with shared voting power/investment power with respect to such securities. Jerome R. Baier is a portfolio manager for NIMC and manages the portfolio which holds such securities. Northwestern Mutual currently is the beneficial owner of $40,000,000 principal amount of CONSOL Energy Inc. 7.875% Senior Notes due 2012

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(CUSIP No. 20854PAB5). Mason Street Advisors, LLC, a wholly owned company of Northwestern Mutual, is an investment adviser to Northwestern Mutual and certain Northwestern Mutual affiliated entities, and therefore may be deemed to be the indirect beneficial owner that shares voting power/investment power of CONSOL Energy Inc. Common Stock (CUSIP No. 20854P109) currently held by the following Northwestern Mutual-affiliated entities: Mason Street Funds, Inc. — Aggressive Growth Fund (49,700 shares) and Northwestern Mutual Series Fund, Inc. — Aggressive Growth Portfolio (317,600 shares). Northwestern Mutual and its affiliates may, in the ordinary course of business, take part in transactions involving the real property of the Company or its affiliates. However, Northwestern Mutual does not concede that any of the foregoing necessarily constitutes a material relationship under S-K 507 that is required to be disclosed in this prospectus.

38.	J.A. Syme, D.P. McDougall, J.H. Szymanski and D.W. Huthwaite hold voting and dispositive power over the securities held by this selling stockholder.

39.	G. Stacy Smith and Reid Walker hold voting and dispositive power over the securities held by this selling stockholder.

40.

41.	Wexford Capital LLC by reason of its status as manager of Wexford Catalyst Investors LLC and Wexford Spectrum may be deemed to own beneficially the common stock of which these selling stockholders possess beneficial ownership.

42.	Mark A. Buntz holds sole voting and dispositive power over the securities held by this selling stockholder.

43.	G. Stacy Smith, Reid Walker and Patrick Walker hold voting and dispositive power over the securities held by this selling stockholder.

44.	Mr. Zajdel served as the Director—Investor Relations of CONSOL Energy Inc. from October 1, 2000 to August 8, 2005, when he became the Director—Investor Relations and Public Relations of CNX Gas Corporation.

45.	PBK Holdings, Inc. is the general partner of Ziff Asset Management, L.P., and Philip B Korsant is the sole shareholder of PBK Holdings, Inc.

46.	Blackrock Advisors Inc. shares voting and dispositive power with respect to the securities held by these selling stockholders.

47.	State Street Research & Management Company shares voting and dispositive power with respect to the securities held by these selling stockholders.

48.	Richard S. Strong has voting and dispositive power with respect to the securities held by this selling stockholder.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 200 million shares of common stock, $0.01 par value per share, and 5 million shares of preferred stock, $0.01 par value per share. The following description of our capital stock is qualified in its entirety by reference to our certificate of incorporation and bylaws, which we encourage you to read.

Common Stock

There are a total of 150,833,334 shares of common stock outstanding, and an additional 2,500,000 shares reserved for issuance to employees pursuant to our equity incentive plan. As of December 15, 2005, we had 2 record holders and more than 400 beneficial holders of our common stock. Additionally, upon effectiveness of this registration statement we will have more than 1,100,000 publicly held shares, with an aggregate market value (assuming a $16 per share trading price) in excess of $60 million.

Voting Rights

The holders of common stock are entitled to one vote per share on all matters submitted to a vote of the stockholders. Cumulative voting of shares of common stock is prohibited, which means that the holders of a majority of shares voting for the election of directors can elect all members of our board of directors. Except as otherwise required by applicable law and except for certain matters set forth in our certificate of incorporation, some of which are discussed below, a majority vote is sufficient for any act of stockholders.

Dividend Rights

Subject to the preferences that may be applicable to any outstanding preferred stock, the holders of common stock are entitled to receive ratably such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for the payment of dividends.

Liquidation Rights

In the event of our liquidation, dissolution, or winding up, the holders of common stock are entitled to share ratably in all assets remaining after payment of liabilities and amounts owed to holders of preferred stock, if any. All outstanding shares of our common stock are fully paid and non-assessable.

Other Matters

The holders of common stock have no preemptive or conversion rights or other subscription rights, and there are no redemption or sinking fund provisions applicable to the common stock.

The rights, preferences and privileges of holders of common stock are subject to, and may be injured by, the rights of the holders of shares of any series of preferred stock that the board of directors may designate and issue in the future. The issuance of preferred stock could decrease the amount of earnings and assets available for distribution to holders of common stock or adversely affect the rights and powers of the holders of common stock, including their voting rights.

Preferred Stock

We are authorized to issue up to 5 million shares of preferred stock, in one or more series, having rights senior to our common stock. Our board of directors is authorized to establish the powers, rights, preferences, privileges and designations of one or more series of preferred stock without further stockholder approval.

To date, no shares of our preferred stock have been issued, nor has our board of directors designated any rights or preferences of any authorized shares of preferred stock. The rights, preferences, privileges and

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restrictions of any series of preferred stock issued by us in the future will be fixed by a certificate of designation relating to each series specifying the terms of the preferred stock, including:

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the maximum number of shares in the series and the distinctive designation;

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the terms on which dividends will be paid, if any, including whether dividends will be cumulative or non-cumulative;

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the terms on which the shares may be redeemed, if at all;

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the liquidation preference, if any;

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the terms and conditions, if any, on which the shares of the series will be convertible into, or exchangeable for, shares of any other class or classes of capital stock;

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restrictions on the issuance of shares;

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the voting rights and powers, if any, on the shares of the series; and

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any or all other powers, privileges, preferences and rights, and qualifications, limitations or restrictions of the shares.

Anti-Takeover Effects of Delaware Law, Our Certificate of Incorporation and Our Bylaws

Some provisions of Delaware law and some of the provisions included in our certificate of incorporation and our bylaws could make the following more difficult:

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the acquisition of CNX Gas by means of a tender offer;

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the acquisition of CNX Gas by means of a proxy contest or otherwise; or

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the removal of CNX Gas’ incumbent officers and directors.

These provisions, as well as our ability to issue preferred stock, are designed to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us first to negotiate with our board of directors. We believe that the benefits of increased protection give us the potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us, and that the benefits of this increased protection outweigh the disadvantages of discouraging those proposals, because negotiation of those proposals could result in an improvement of their terms.

Important Information Contained in the Certificate of Incorporation and Bylaws

Election and Removal of Directors

The board of directors will consist of between 3 and 11 directors; the exact number will be determined by a majority of the board of directors. Effective upon the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, the board of directors will be divided into three classes of directors, as nearly equal in members as possible.

The term of office for all class first directors will end at the first annual meeting of stockholders following such classification. For class second directors, their term of office will expire at the second annual meeting of stockholders following such classification, and the term of office for class third directors will end at the third annual meeting following such classification. Thereafter, directors in each class shall be elected for a three-year term, with one class of directors being elected each year at the annual meeting of stockholders. Directors will remain in office until their successors have been duly elected and qualified. This system of electing and removing directors may discourage a third party from making a tender offer or otherwise attempting to obtain control of us because it will generally make it more difficult for stockholders to replace a majority of the directors.

Prior to the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, any director or the entire board of directors may be removed, with or

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without cause by the affirmative vote of a majority of the outstanding shares of common stock and preferred stock, voting as a single class. Following such date, no director is permitted to be removed except for cause and by a vote of holders of at least 66²/3% of the voting power of our outstanding shares of stock.

Prior to the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, any vacancy on the board may be filled by the affirmative vote of a majority of the outstanding shares of capital stock. Following such date, any vacancy occurring on the board and any newly created directorship may only be filed by a majority of the remaining directors or by the sole remaining director in office. In the event of the death, resignation, retirement, removal or disqualification of a director during his or her term, his or her successor will serve until the meeting of stockholders at which directors are elected, and his or her successor is elected and qualified, or until his or her earlier resignation or removal.

Stockholder Meetings and Advance Notice Requirements for Stockholder Nominations and Proposals

Prior to the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, our certificate of incorporation provides that special meetings of stockholders may be called only by the chairman of our board of directors, a resolution adopted by the majority of our board of directors or by a written request of the holders of a majority of our common stock. Following such date, special meetings may be called by the chairman or a resolution adopted by the majority of our board of directors, but may not be called by holders of our common stock.

The bylaws require that advance notice be delivered to us of any business to be brought by a stockholder before an annual or special meeting of stockholders and provide for procedures to be followed by stockholders in nominating persons for election to our board of directors. In the case of an annual meeting, stockholders generally are required to give written notice of a nomination or proposal to the secretary of our company not later than 90 days nor earlier than 120 days before the first anniversary of the preceding year’s annual meeting. In the event that the date of the annual meeting is more than 30 days before or more than 60 days after the anniversary date, a stockholder must give notice of a nomination or proposal not earlier than 120 days prior to the new meeting date and not later than 90 days prior to the new meeting date or 10 days after the day on which the meeting is first announced publicly. Notwithstanding the above, our certificate of incorporation states that any such advance notice procedure for the nomination of directors is not applicable to CONSOL Energy until the fist date on which they fail to own at least fifty percent (50%) of our issued and outstanding common stock.

For special meetings, only the business set forth in the notice of that special meeting to stockholders may be conducted. Nominations for the election of directors at that special meeting will be permitted to be made only by the board of directors, or if the board of directors determines that directors are to be elected at a special meeting, by a stockholder, who is at the time notice is given, a stockholder of record and entitled to vote at that special meeting. If we call a special meeting of stockholders to elect directors, a stockholder will have to give notice of a nomination to the secretary of our company not earlier than 120 days prior to the special meeting and not later than 90 days prior to the special meeting or 10 days after notice of the meeting.

With regard to either an annual or a special stockholder meeting, a stockholder’s notice to the secretary of our company is required to include specific information regarding the stockholder giving the notice, the director nominee or other business proposed by the stockholder, as applicable, as may be required by certain SEC rules and regulations, and as provided in the bylaws.

Action by Written Consent of the Stockholders

Prior to the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, any action required or permitted to be taken at any annual or special meeting may be taken without a meeting, without prior notice and without a vote, if a consent or consents in writing, setting forth the action taken, is signed by the holders of outstanding capital stock having not less than

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the minimum required votes to authorize such action if taken at a meeting. Following such date, all stockholder actions must be effected at a duly called annual or special meeting of the stockholders, and may not by effected by written consent.

Modification or Repeal of Bylaws by the Board of Directors

The bylaws or any bylaw may be altered or repealed by a majority of the members of our board of directors or stockholders holding two-thirds of the number of outstanding shares of capital stock entitled to vote at such meeting. However, following the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, the vote of at least 80% of the stockholders is required to amend, alter or repeal certain sections of the bylaws relating to stockholder meetings, action by written consent, board nomination matters, the size and election of the board of directors and amendments to the bylaws.

Corporate Opportunities and Conflicts of Interest

Our certificate of incorporation and certain other agreements between us and CONSOL Energy permits CNX Gas and any affiliated company to enter into and perform agreements and transactions with CONSOL Energy or any of its affiliated companies. No such agreement or the performance thereof will be considered contrary to any fiduciary duty that CONSOL Energy may owe to CNX Gas or any stockholder by virtue of its position as a significant stockholder, nor to any fiduciary duty owed by the directors and officers of CNX Gas, CONSOL Energy, or any affiliated company. All such directors and officers of CNX Gas or any affiliated company will be deemed to have acted in good faith and shall not be deemed to have breached their duty of loyalty if: (i) such agreement was entered into while we were a wholly-owned subsidiary of CONSOL Energy, (ii) the material facts of the agreement or contract are disclosed to the board of directors (or applicable committee) and a majority of the independent members of the board, or committee (even if less than a majority of the whole board or committee), approve the agreement or contract, (iii) the material facts of the agreement or contract are known to the holders of capital stock of CNX Gas and the holders (excluding CONSOL Energy or other interested party) of a majority of the shares of stock approve and ratify the agreement or contract or (iv) such agreement or contract is fair to CNX Gas when entered into, approved or ratified.

Except to the extent set forth in the master cooperation and safety agreement, CONSOL Energy is under no duty to refrain from (i) engaging in the same or similar lines of business as CNX Gas or its subsidiaries or (ii) doing business with any customer, client or vendor of CNX Gas. Our certificate and the master cooperation and safety agreement provide that if CONSOL Energy is first to acquire knowledge of a transaction or opportunity that may be a corporate opportunity for both CNX Gas and CONSOL Energy, then the corporate opportunity shall belong to CONSOL Energy (and no officer or director of CONSOL Energy has any duty to inform CNX Gas of such opportunity) and CNX Gas shall renounce all rights to that corporate opportunity and waive any claim that such corporate opportunity should have been presented to it. Our master cooperation and safety agreement also provides that if CNX Gas is first to acquire knowledge of a transaction or opportunity that may be a corporate opportunity for both CNX Gas and CONSOL Energy, then the corporate opportunity shall belong to CNX Gas (and no officer or director of CNX Gas has any duty to inform CONSOL Energy of such opportunity).

Our certificate of incorporation also provides that if any officer, employee or director of CNX Gas who is also an officer, employee or director of CONSOL Energy acquires knowledge of a transaction or opportunity that may be a corporate opportunity for both CNX Gas and CONSOL Energy, then the corporate opportunity shall belong to CONSOL Energy and CNX Gas shall renounce all rights to that corporate opportunity and waive any claim that such corporate opportunity should have been presented to it if such director, officer or employee acts in a manner consistent with the following policy: (i) a corporate opportunity offered to a person who is a director, but not an officer or employee, of CNX Gas who is also a director, officer or employee of CONSOL Energy shall belong to CNX Gas only if such opportunity is expressly offered to such person in his capacity as a director of CNX Gas and otherwise shall belong to CONSOL Energy, and (ii) an opportunity offered to any person who is both an officer of CNX Gas and CONSOL Energy shall belong to CNX Gas unless such opportunity is expressly

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offered to such person solely in his capacity as an officer of CONSOL Energy, in which case the opportunity shall belong to CONSOL Energy. If an officer or director of CNX Gas who also serves as an officer or director of CONSOL Energy acquires knowledge of a potential transaction or matter which may be a corporate opportunity for both CNX Gas and CONSOL Energy in any other manner, such officer or director has no duty to present the corporate opportunity to CNX Gas which shall renounce all rights to it.

Limitation on Liability of Directors

Section 145 of the Delaware General Corporation Law (“DGCL”) provides that a corporation may indemnify directors and officers as well as other employees and individuals against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement in connection with any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, in which such person is made a party by reason of the fact that the person is or was a director, officer, employee or agent of CNX Gas (other than an action by or in the right of CNX Gas—a “derivative action”), if they acted in good faith and in a manner they reasonably believed to be in, or not opposed to, the best interests of CNX Gas and, with respect to any criminal action or proceeding, had no reasonable cause to believe their conduct was unlawful. A similar standard is applicable in the case of derivative actions, except that indemnification only extends to expenses (including attorneys’ fees) incurred in connection with the defense or settlement of such action, unless and only to the extent that a court has approved the expenses where the person seeking indemnification has been found liable to CNX Gas. The statute provides that it is not exclusive of other indemnification that may be granted by a corporation’s certificate of incorporation, bylaws, disinterested director vote, stockholder vote, agreement, or otherwise.

Our certificate of incorporation provides that no director shall be liable to CNX Gas or our stockholders for monetary damages for breach of fiduciary duty as a director, unless the exemption or limitation of liability is not permitted under Delaware law. Currently, Section 102(b)(7) of the DGCL requires that liability be imposed for the following:

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any breach of the director’s duty of loyalty to CNX Gas or our stockholders;

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any act or omission not in good faith or which involved intentional misconduct or a knowing violation of law;

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unlawful payments of dividends or unlawful stock repurchases or redemptions as provided in Section 174 of the DGCL; and

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any transaction from which the director derived an improper personal benefit.

Our bylaws provide that, to the fullest extent permitted by law, we will indemnify any person made or threatened to be made a party to any action by reason of the fact that the person, or a person for whom he or she is the legal representative, is or was our director or officer. We will reimburse the expenses, including attorneys’ fees, incurred by a person indemnified by this provision. Any repeal, modification or amendment of this provision will not reduce our indemnification obligations relating to actions taken before any such repeal, modification or amendment.

We intend to obtain policies insuring our directors and officers and those of our subsidiaries against certain liabilities they may incur in their capacity as directors and officers. Under these policies, the insurer, on our behalf, may also pay amounts for which we have granted indemnification to the directors or officers.

Delaware Business Combination Statute

Prior to the date when CONSOL Energy first fails to beneficially own at least fifty percent (50%) of our issued and outstanding common stock, we will not be subject to Section 203 of the DGCL. Following such date,

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we will be subject to Section 203 of the DGCL, an anti-takeover law. In general, Section 203 prohibits a publicly held Delaware corporation from engaging in a “business combination” with an “interested stockholder” for a period of three years following the date the person became an interested stockholder, unless:

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the business combination or the transaction in which the person became an interested stockholder is approved by the board of directors;

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after consummation of the transaction in which the person became an interested stockholder, such stockholder owned at least 85% of CNX Gas’ voting stock at the time the transaction commenced; or

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the business combination is approved by holders of at least two-thirds of CNX Gas’ voting stock not held by the interested stockholder.

Generally, a “business combination” includes a merger, asset or stock sale or other transaction resulting in a financial benefit to the interested stockholder. Generally, an “interested stockholder” is a person who, together with affiliates and associates, owns or, within three years prior to the determination of interested stockholder status, did own, 15% or more of a corporation’s voting stock. The existence of this provision may have an anti-takeover effect with respect to transactions not approved in advance by the board of directors, including discouraging attempts that might result in a premium over the market price for the shares of common stock held by stockholders.

Transfer Agent and Registrar

Our transfer agent and registrar for our common stock is National City Bank.

PLAN OF DISTRIBUTION

We are registering the common stock covered by this prospectus to permit selling stockholders to conduct public secondary trading of these shares and interests therein from time to time after the date of this prospectus. Under the registration rights agreement we entered into with selling stockholders, we agreed to, among other things, bear all expenses, other than brokers’ or underwriters’ discounts and commissions, in connection with the registration and sale of the common stock covered by this prospectus. We will not receive any of the proceeds of the sale of the common stock offered by this prospectus. The aggregate proceeds to the selling stockholders from the sale of the common stock will be the purchase price of the common stock less any discounts and commissions. A selling stockholder reserves the right to accept and, together with their agents, to reject, any proposed purchases of common stock to be made directly or through agents.

The common stock offered by this prospectus may be sold from time to time to purchasers:

•

directly by the selling stockholders and their successors, which includes their donees, pledgees or transferees or their successors-in-interest, however, in order for a donee, pledgee, transferee or other successor-in-interest to sell shares of common stock under cover of the registration statement of which this prospectus is part, unless permitted by law, we must provide the seller with a prospectus supplement and/or, if appropriate, amend such registration statement amending the list of selling stockholders to include the donee, pledgee, transferee, or other successors-in-interest as selling stockholders under this prospectus for delivery in connection with such sale, or

•

through underwriters, broker-dealers or agents, who may receive compensation in the form of discounts, commissions or agent’s commissions from the selling stockholders or the purchasers of the common stock. These discounts, concessions or commissions may be in excess of those customary in the types of transactions involved.

To our knowledge, there are currently no plans, arrangements or understandings between any selling stockholders and any underwriter, broker-dealer or agent regarding the sale of the common stock by the selling stockholders.

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Upon being notified by a selling stockholder that any material arrangement has been entered into with an underwriter, broker, dealer or agent regarding the sale of the common stock covered by this prospectus, a revised prospectus or prospectus supplement, if required, will be distributed which will set forth the aggregate amount and the terms of the offering, including the name or names of any underwriters, dealers or agents, any discounts, commissions and other items constituting compensation from the selling stockholders, and any discounts, commissions or concessions allowed or reallowed or paid to dealers. The prospectus supplement and, if necessary, a post-effective amendment to the registration statement of which this prospectus forms a part, will be filed with the SEC to reflect the disclosure of additional information with respect to the distribution of the common stock.

The selling stockholders and any underwriters, broker-dealers or agents who participate in the sale or distribution of the common stock may be deemed to be “underwriters” within the meaning of the Securities Act. The selling stockholders identified as registered broker-dealers in the selling stockholders table above (under “Selling Stockholders”) are deemed to be underwriters. As a result, any profits on the sale of the common stock by such selling stockholders and any discounts, commissions or agent’s commissions or concessions received by any such broker-dealer or agents may be deemed to be underwriting discounts and commissions under the Securities Act. Selling stockholders who are deemed to be “underwriters” within the meaning of Section 2(11) of the Securities Act will be subject to prospectus delivery requirements of the Securities Act. Underwriters are subject to certain statutory liabilities, including, but not limited to, Sections 11, 12 and 17 of the Securities Act.

The common stock and interests therein may be sold in one or more transactions at:

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fixed prices;

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prevailing market prices at the time of sale;

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prices related to such prevailing market prices;

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varying prices determined at the time of sale; or

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negotiated prices.

These sales may be effected in one or more transactions:

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on any national securities exchange or quotation on which the common stock may be listed or quoted at the time of the sale;

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in the over-the-counter market;

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in transactions other than on such exchanges or services or in the over-the-counter market;

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through the writing of options (including the issuance by the selling stockholders of derivative securities), whether the options or such other derivative securities are listed on an options exchange or otherwise;

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through the settlement of short sales made after the effectiveness of the registration statement of which this prospectus is a part; or

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through any combination of the foregoing.

These transactions may include block transactions or crosses. Crosses are transactions in which the same broker acts as an agent on both sides of the trade.

In connection with the sales of the common stock, the selling stockholders may enter into hedging transactions (but may not engage in any short selling activities prior the effectiveness of the registration statement of which this prospectus is a part) with broker-dealers or other financial institutions which in turn may:

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engage in short sales of the common stock in the course of hedging their positions;

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sell the common stock short and deliver the common stock to close out short positions;

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•

loan or pledge the common stock to broker-dealers or other financial institutions that in turn may sell the common stock;

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enter into option or other transactions with broker-dealers or other financial institutions that require the delivery to the broker-dealer or other financial institution of the common stock, which the broker-dealer or other financial institution may resell under the prospectus; or

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enter into transactions in which a broker-dealer makes purchases as a principal for resale for its own account or through other types of transactions.

We have been approved, for listing our common stock on the New York Stock Exchange under the symbol “CXG.” However, we can give no assurances as to the development of liquidity or any trading market for the common stock.

There can be no assurance that any selling stockholder will sell any or all of the common stock under this prospectus. Further, we cannot assure you that any such selling stockholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the U.S. in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be sold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be sold unless it has been registered or qualified for sale or an exemption from registration or qualification is available and complied with.

The selling stockholders and any other person participating in the sale of the common stock will be subject to the Exchange Act. The Exchange Act rules include, without limitation, Regulation M, which may limit the timing of purchases and sales of any of the common stock by the selling stockholders and any other such person. In addition, Regulation M may restrict the ability of any person engaged in the distribution of the common stock to engage in market-making activities with respect to the particular common stock being distributed. This may affect the marketability of the common stock and the ability of any person or entity to engage in market-making activities with respect to the common stock.

We have agreed to indemnify the selling stockholders against certain liabilities, including liabilities under the Securities Act.

We have agreed to pay substantially all of the expenses incidental to the registration, offering and sale of the common stock to the public, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions or transfer taxes relating to the sale of shares of our common stock.

In compliance with guidelines of the NASD, Inc., the maximum commission or discount to be received by any NASD member or independent broker-dealer may not exceed 8% of the aggregate principal amount of the securities offered pursuant to this prospectus.

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REGISTRATION RIGHTS

Holders of our common stock who purchased in our recent private placement and CONSOL Energy are entitled to the benefits of a registration rights agreement among us, CONSOL Energy and Friedman, Billings, Ramsey & Co., Inc. Pursuant to the registration rights agreement, we agreed, at our expense, to file with the SEC no later than 210 days following the closing of the private placement a shelf registration statement registering for resale the shares of our common stock sold in the private placement, the shares of common stock held by CONSOL Energy and any additional shares of common stock issued in respect thereof whether by stock dividend, stock split or otherwise. This prospectus is part of the shelf registration statement that we filed to meet in part our obligations under the registration rights agreement.

We are obligated to use our commercially reasonable efforts to cause this shelf registration statement to become effective under the Securities Act as soon as practicable after the filing and to continuously maintain the effectiveness of this shelf registration statement under the Securities Act until the first to occur of:

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the sale or other disposition of all of the shares of common stock covered by the shelf registration statement pursuant to a registration statement or pursuant to Rule 144 under the Securities Act;

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such time as all of the shares of our common stock sold in this offering and covered by the shelf registration statement and not held by affiliates of us are, in the opinion of counsel, eligible for sale pursuant to Rule 144(k) (or any successor or analogous rule) under the Securities Act;

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the shares covered by the registration statement have been sold to us or any of our subsidiaries; or

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the second anniversary of the initial effective date of the shelf registration statement.

If we choose to file a registration statement for an initial public offering by us of our common stock, all holders of our common stock sold in the private placement and CONSOL Energy and each of their respective direct and indirect transferees may elect to participate in the registration in order to resell their shares, subject to:

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compliance with the registration rights agreement;

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cutback rights on the part of the underwriters; and

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other conditions and limitations that may be imposed by the underwriters.

In addition to the above stated rights, CONSOL Energy may request registration, which we refer to as a demand registration, under the Securities Act of all or any portion of its shares covered by the registration rights agreement and we will be obligated to register the shares as requested by CONSOL Energy. The maximum number of demand registrations that we are required to effect is five.

Additionally, if we at any time intend to file on our behalf or on behalf of any of our other stockholders a registration statement in connection with a public offering of any of our securities on a form and in a manner that would permit the registration for offer and sale of our common stock held by CONSOL Energy, CONSOL Energy has the right to include its shares in that offering.

Upon an initial public offering by us, the holders of our common stock that are beneficiaries of the registration rights agreement will not be able to sell any remaining shares not included in the initial public offering for a period of up to 60 days following the effective date of the registration statement filed in connection with the initial public offering.

Notwithstanding the foregoing, we will be permitted, under limited circumstances, to suspend the use, from time to time, of the prospectus that is part of this shelf registration statement of which this prospectus is a part (and therefore suspend sales under this registration statement) for certain periods, referred to as “blackout periods,” if, among other things, any of the following occurs:

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the representative of the underwriters of an underwritten offering of primary shares by us has advised us that the sale of shares of our common stock under the shelf registration statement would have a material adverse effect on our initial public offering;

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•

a majority of the members of our board of directors, in good faith, determines that (1) the offer or sale of any shares of our common stock would materially impede, delay or interfere with any proposed financing, offer or sale of securities, acquisition, merger, tender offer, business combination, corporate reorganization, consolidation or other significant transaction involving us; (2) after the advice of counsel, the sale of the shares covered by the shelf registration statement would require disclosure of non-public material information not otherwise required to be disclosed under applicable law; and (3) either (x) we have a bona fide business purposes for preserving the confidentiality of the proposed transaction, (y) disclosure would have a material adverse effect on us or our ability to consummate the proposed transaction, or (z) the proposed transaction renders us unable to comply with SEC requirements; or

•

a majority of the members of our board of directors, in good faith, determines that we are required by law, rule or regulation to supplement the shelf registration statement or file a post-effective amendment to the shelf registration statement in order to incorporate information into the shelf registration statement for the purpose of (1) including in the shelf registration statement any prospectus required under Section 10(a)(3) of the Securities Act; (2) reflecting in the prospectus included in the shelf registration statement any facts or events arising after the effective date of the shelf registration statement (or the most-recent post-effective amendment) that, individually or in the aggregate, represents a fundamental change in the information set forth in the prospectus; or (3) including in the prospectus included in the shelf registration statement any material information with respect to the plan of distribution not disclosed in the shelf registration statement or any material change to such information.

The cumulative blackout periods in any 12 month period commencing on the closing of the offering may not exceed an aggregate of 90 days and furthermore may not exceed 60 days in any 90-day period, except as a result of a review of any post-effective amendment by the SEC prior to declaring any post-effective amendment to the registration statement effective; provided we have used all commercially reasonable efforts to cause such post-effective amendment to be declared effective.

In addition to this limited ability to suspend use of the shelf registration statement, until we are eligible to incorporate by reference into the registration statement our periodic and current reports, which will not occur until at least one year following the end of the month in which our first registration statement filed under the Securities Act is declared effective and we become subject to the reporting requirements of the Exchange Act, we will be required to amend or supplement the shelf registration statement to include our quarterly and annual financial information and other developments material to us. Therefore, sales under the shelf registration statement (of which this prospectus is a part) will be suspended until the amendment or supplement, as the case may be, is filed and effective.

We cannot, without the prior written consent of CONSOL Energy and the holders of a majority of the outstanding registrable shares, enter into any agreement with current or prospective holders that would allow them (i) to include their shares in any registration statement filed pursuant to the registration rights agreement, unless such holders reduce the amount of their shares to be included if necessary to allow the inclusion of all the shares of the holders under the registration rights agreement or (ii) have their common stock registered on a registration statement that could be declared effective prior to or within 180 days of the effective date of any registration statement filed pursuant to the registration rights agreement.

A holder that sells our common stock pursuant to a shelf registration statement or as a selling stockholder pursuant to an underwritten public offering generally will be required to be named as a selling stockholder in the related prospectus and to deliver a prospectus to purchasers, will be subject to certain of the civil liability provisions under the Securities Act in connection with such sales and will be bound by the provisions of the registration rights agreement that are applicable to such holder (including certain indemnification rights and obligations). In addition, each holder of our common stock will be required to deliver information to be used in connection with the shelf registration statement within a twenty business-day period following receipt of notice from us in order to have such holder’s shares of our common stock included in the shelf registration statement.

127

Each common stock certificate representing the privately placed shares may contain a legend to the effect that the holder thereof, by its acceptance thereof, will be deemed to have agreed to be bound by the provisions of the registration rights agreement. In that regard, each selling stockholder will be deemed to have agreed that, upon receipt of notice of the occurrence of any event which makes a statement in the prospectus which is part of the shelf registration statement untrue in any material respect or which requires the making of any changes in such prospectus in order to make the statements therein not misleading, or of certain other events specified in the registration rights agreement, such selling stockholder will suspend the sale of our common stock pursuant to this prospectus until we have amended or supplemented this prospectus to correct such misstatement or omission and have furnished copies of such amended or supplemented prospectus to such holder or we have given notice that the sale of the common stock may be resumed.

In connection with our filing of a registration statement, we agreed to use our commercially reasonable efforts to satisfy the criteria for listing and list or include (if we meet the criteria for listing on such exchange or market) our common stock on the NYSE, American Stock Exchange or The Nasdaq National Market (as soon as practicable, including seeking to cure in our listing or inclusion application any deficiencies cited by the exchange or market), and thereafter maintain the listing on such exchange.

We will bear certain expenses incident to our registration obligations upon exercise of these registration rights, including the payment of federal securities law and state blue sky registration fees, except that we will not bear any underwriting discounts or commissions relating to the sale of shares of our common stock. We have agreed to indemnify each selling stockholder for certain violations of federal or state securities laws in connection with any registration statement in which such selling stockholder sells its shares of our common stock pursuant to these registration rights. Each selling stockholder in turn agreed to indemnify us for federal or state securities law violations that occur in reliance upon written information it provides for us in the registration statement.

We will also provide each holder of registrable shares copies of the prospectus that is a part of the registration statement, notify such holder when the registration statement has become effective, and take certain other actions as are required to permit unrestricted resales.

The preceding summary of certain provisions of the registration rights agreement is not intended to be complete, and is subject to, and qualified in its entirety by reference to, all of the provisions of the registration rights agreement and you should read this summary together with the complete text of the registration rights agreement.

VALIDITY OF SHARES

The validity of the shares offered hereby has been passed upon for us by Buchanan Ingersoll PC, Pittsburgh, Pennsylvania.

EXPERTS

The financial statements as of December 31, 2004 and 2003 and for each of the three years in the period ended December 31, 2004 included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The information included in this prospectus for the year ended December 31, 2004, and as of March 31, 2005, relating to our total gas supply and our owned gas reserves is derived from reserve reports prepared or reviewed by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. This information is included or incorporated by reference in this prospectus in reliance upon these firms as experts in matters contained in the reports.

128

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 prospectus.

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

G-1

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 prospectus, 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 federal income taxes. The estimated future net revenues are discounted at an annual rate of 10% in accordance with the SEC’s

G-2

practice, to determine their “present value.” The present value is shown to indicate the effect of time on the value of the revenue stream and should not be construed as being the fair market value of the properties. Estimates of future net revenues are made using oil and natural gas prices and operating costs at the date indicated and held constant for the life of the reserves.

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

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

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

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

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

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.

G-3

INDEX TO FINANCIAL STATEMENTS


		Page
Unaudited Financial Statements for the Three and Nine Months Ended September 30, 2005 and 2004
Consolidated Statements of Income		F-2
Consolidated Balance Sheets		F-3
Consolidated Statements of Cash Flow		F-4
Consolidated Statements of Stockholders’ Equity		F-5
Notes to Unaudited Consolidated Financial Statements		F-6
Financial Statements for the Years Ended December 31, 2004, 2003 and 2002
Report of Independent Registered Public Accounting Firm		F-16
Consolidated Statements of Income		F-17
Consolidated Balance Sheets		F-18
Consolidated Statements of Stockholder’s Equity		F-19
Consolidated Statements of Cash Flows		F-20
Notes to Audited Financial Statements		F-21

F-1

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

September 30, 2005

(Unaudited)

(Dollars in thousands, except per share data)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Revenue and Other Income:
Outside Sales	$	83,998	$	68,409	$	223,937	$	187,651
Related Party Sales		1,926		993		5,325		20,535
Purchased Gas Sales		88,288		49,349		157,545		65,419
Other Income		2,100		2,230		6,627		5,068

Total Revenue and Other Income		176,312		120,981		393,434		278,673
Costs and Expenses:
Lifting Costs		6,907		5,929		19,087		16,666
Gathering and Compression Costs		10,696		10,077		29,918		26,073
Royalty		10,042		8,488		24,505		24,643
Purchased Gas Costs		89,653		49,752		159,739		65,969
Other		5,289		5,096		14,874		12,718
Equity in (Earnings) Loss of Affiliates		88		731		220		1,882
Selling, General and Administrative		2,151		1,697		5,632		4,716
Depreciation, Depletion and Amortization		8,671		8,222		25,883		24,103

Total Costs and Expenses		133,497		89,992		279,858		176,770

Earnings Before Income Taxes		42,815		30,989		113,576		101,903
Income Taxes		16,745		12,117		43,988		39,848

Net Income	$	26,070	$	18,872	$	69,588	$	62,055


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Earnings per Share:
Basic	$	0.19	$	0.15	$	0.54	$	0.50

Dilutive	$	0.19	$	0.15	$	0.54	$	0.50

Weighted Average Number of Common Shares Outstanding:
Basic		139,294,276		122,896,667		128,422,601		122,896,667

Dilutive		139,416,414		123,009,664		128,499,081		122,965,131


	Three Months Ended September 30,				Nine Months Ended September 30,
_{Pro Forma}	2005		2004		2005		2004
Earnings per Share:
Basic EPS	$	0.17	$	0.13	$	0.46	$	0.41

Dilutive EPS	$	0.17	$	0.13	$	0.46	$	0.41

Weighted Average Number of Common Shares Outstanding:
Basic		150,833,334		150,833,334		150,833,334		150,833,334

Dilutive		150,955,472		150,946,331		150,909,814		150,901,798

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

F-2

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

September 30, 2005

(Dollars in thousands, except per share data)


	September 30, 2005			December 31, 2004
	(unaudited)
ASSETS
Current Assets:
Cash and Cash Equivalents	$	29,556		$	3
Accounts Receivable:
Trade		37,652			700
Other		64			735
Deferred Taxes		—			8,301
Other Current Assets		9,295			6,585

Total Current Assets		76,567			16,324
Property and Equipment, Net		688,791			640,876
Other Assets		11,113			14,951
Derivatives		—			3,766
Investments in Equity Affiliates		49,850			47,373

TOTAL ASSETS	$	826,321		$	723,290

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	24,748		$	24,002
Accounts Payable Related Party		9,551			—
Accrued Royalties Payable		10,185			8,701
Accrued Severance Taxes		3,162			2,337
Accrued Income Taxes		11,040			941
Other Accrued Liabilities		13,128			6,112

Total Current Liabilities		71,814			42,093
Deferred Taxes		17,635			183,624
Other Liabilities		12,340			10,202
Salary Retirement		119			—
Well Plugging Liabilities		10,384			8,685
Derivatives		81,840			13,027
Postretirement Benefits Other Than Pension		3,298			3,103

Total Liabilities		197,430			260,734

Stockholders’ Equity:
Common Stock, $0.01 par value: 200,000,000 shares authorized, 150,833,334 issued and outstanding at September 30, 2005		1,508			—
Capital in Excess of Par Value		775,792			215,710
Retained Earnings (Deficit)		(98,110	)		252,469
Accumulated Other Comprehensive Loss		(50,299	)		(5,623	)

Total Stockholders’ Equity		628,891			462,556

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	826,321		$	723,290

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

F-3

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOW

September 30, 2005

(Unaudited)

(Dollars in thousands, except per share data)


	Nine Months Ended September 30,
	2005			2004
Operating Activities:
Net Income	$	69,588		$	62,055
Adjustments to Reconcile Net Income to Net Cash (Used In) Provided By Operating Activities:
Depreciation, Depletion and Amortization		25,883			24,103
Income Taxes		11,040			—
Deferred Income Taxes		32,948			39,848
Equity in Loss of Affiliates		220			1,882
Changes in Operating Assets:
Accounts Receivable		(36,281	)		(240	)
Other Current Assets		(2,710	)		(809	)
Changes in Other Assets		4,374			(1,226	)
Changes in Operating Liabilities:
Accounts Payable		10,297			(13,832	)
Other Current Liabilities		9,325			5,309
Changes in Other Liabilities		63			5,742
Other		149			(9	)

Net Cash Provided by Operating Activities		124,896			122,823

Investing Activities:
Capital Expenditures		(70,207	)		(60,031	)
Investment in Equity Affiliates		(2,697	)		(1,356	)

Net Cash Used in Investing Activities		(72,904	)		(61,387	)

Financing Activities:
Issuance of Common Stock		420,167			—
Dividends Paid		(420,167	)		—
Payment to Parent		(22,439	)		(61,438	)

Net Cash Used in Financing Activities		(22,439	)		(61,438	)
Net Increase (Decrease) in Cash and Cash Equivalents		29,553			(2	)
Cash and Cash Equivalents at Beginning of Period		3			4

Cash and Cash Equivalents at End of Period	$	29,556		$	2

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

F-4

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

September 30, 2005

(Dollars in thousands, except per share data)


	Common Stock		Capital in Excess of Par Value			Retained Earnings (Deficit)			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity
Balance at December 31, 2004	$	—	$	215,710		$	252,469		$	(5,623	)	$	462,556
(Unaudited)
Net Income		—		—			69,588			—			69,588
Dividends Paid		—		—			(420,167	)		—			(420,167	)
Issuance of Common Stock		1,508		418,659			—			—			420,167
Effect of Tax Basis Step-up		—		162,731			—			—			162,731
Capital Distribution To Parent		—		(21,308	)		—			—			(21,308	)
Gas Cash Flow Hedge (Net of $27,784 tax)		—		—			—			(44,676	)(a)		(44,676	)

Balance at September 30, 2005	$	1,508	$	775,792		$	(98,110	)	$	(50,299	)	$	628,891

(a)	Of the ($44,676) net change in accumulated other comprehensive income/(loss) in the period, $12,959 represents the settlements recognized in net income, while ($57,635) represents unrealized settlements on gas cash flow hedges during the period.

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

F-5

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

September 30, 2005

(Dollars in thousands, except per share data)

Note 1—Basis of Presentation:

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information, and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the three month and nine month period ended September 30, 2005 are not necessarily indicative of the results that may be expected for future periods.

The balance sheet at December 31, 2004 has been derived from the audited consolidated financial statements at that date but does not include all the notes required by generally accepted accounting principles for complete financial statements. For further information, refer to the consolidated financial statements and related notes for the year ended December 31, 2004 also included in this Form S-1A.

On June 21, 2005, the Board of Directors of CONSOL Energy Inc. (CONSOL Energy) authorized the incorporation of CNX Gas Corporation (CNX Gas). On June 30, 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 coalbed methane 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.

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. In August 2005, a Registration Statement on Form S-1 was filed with the SEC with respect to those shares, however the registration statement has not yet been declared effective and the shares may not be offered or sold in the United States absent registration or an applicable exemption from registration. The proceeds (approximately $420,167 including proceeds from the sale of the additional 3.6 million shares) were used to pay a special dividend to CONSOL Energy. For tax purposes, the special dividend to CONSOL Energy resulted in a step-up in the tax basis of the assets contributed by CONSOL Energy to CNX Gas. CNX Gas has recorded a deferred tax asset with respect to the step-up of $162,731 with a corresponding adjustment to stockholders’ equity pursuant to Emerging Issues Task Force Issue No. 94-10, “Accounting by a Company for the Income Tax Effects of Transactions among or with its shareholders under FASB Statement No. 109.”

CONSOL Energy holds approximately 122.9 million shares, or approximately 81.5 percent, of the outstanding shares of CNX Gas’ common stock (before issuance of any shares under CNX Gas’ 2.5 million share equity incentive plan).

Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the reporting period. In calculating earnings per share, CNX Gas utilized the 122.9 million shares issued to CONSOL Energy upon formation for all periods presented and subsequently, until the August 2005 private placement, when the weighted average number of shares increased to reflect the shares sold in the private placement. 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,

F-6

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

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.

The computations for basic and diluted earnings per share are as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Net Income	$	26,070	$	18,872	$	69,588	$	62,055

Weighted Average Number of Common Shares Outstanding:
Basic		139,294,276		122,896,667		128,422,601		122,896,667
Effect of stock options		122,138		112,997		76,480		68,464

Dilutive		139,416,414		123,009,664		128,499,081		122,965,131


Earnings per share:
Basic	$	0.19	$	0.15	$	0.54	$	0.50

Diluted	$	0.19	$	0.15	$	0.54	$	0.50

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


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Net Income	$	26,070	$	18,872	$	69,588	$	62,055

Pro Forma
Weighted Average Number of Common Shares Outstanding:
Basic		150,833,334		150,833,334		150,833,334		150,833,334
Effect of stock options		122,138		112,997		76,480		68,464

Dilutive		150,955,472		150,946,331		150,909,814		150,901,798

Earnings per share:
Basic	$	0.17	$	0.13	$	0.46	$	0.41

Diluted	$	0.17	$	0.13	$	0.46	$	0.41

Note 2—Other Income:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2005		2004		2005		2004
Royalty Income	$	1,766	$	1,883	$	5,698	$	4,151
Third Party Gathering Revenue		294		300		794		784
Miscellaneous		40		47		135		133

Total Other Income	$	2,100	$	2,230	$	6,627	$	5,068

F-7

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

Note 3—Stock-Based Compensation:

CNX Gas has implemented the disclosure-only provisions of Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure-an Amendment of SFAS No. 123” (SFAS No.148). CNX Gas continues to measure compensation expense for its 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. 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. Stock-based compensation expense related to restricted stock units has been reflected in net income for the three and nine month periods ended September 30, 2005. 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 and 148, to stock-based employee compensation:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2005			2004		2005			2004
Net income (loss) as reported	$	26,070		$	18,872	$	69,588		$	62,055
Add: Stock-based compensation expense for restricted stock units		81			—		81			—
Deduct: Total stock-based employee compensation expense determined under Black-Scholes option pricing model and stock-based compensation expense for restricted stock units		(266	)		—		(266	)		—

Pro forma net income (loss)	$	25,885		$	18,872	$	69,403		$	62,055

Earnings per share:
Basic—as reported	$	0.19		$	0.15	$	0.54		$	0.50

Basic—pro forma	$	0.19		$	0.15	$	0.54		$	0.50

Diluted—as reported	$	0.19		$	0.15	$	0.54		$	0.50

Diluted—pro forma	$	0.19		$	0.15	$	0.54		$	0.50

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.

Note 4—Components of Pension and Other Postretirement Benefit Plans Net Periodic Benefit Costs:

Components of net periodic costs (benefits) for the three months and nine months ended September 30 are as follows:


	Pension Benefits				Other Benefits
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,						Nine Months Ended September 30,
	2005		2005		2005			2004			2005			2004
Service costs	$	91	$	91	$	40		$	33		$	120		$	99
Interest costs		28		28		42			40			126			121
Amortization costs (credit)		—		—		(28	)		(29	)		(84	)		(87	)
Recognized net actuarial loss		—		—		11			16			33			47

Benefit costs	$	119	$	119	$	65		$	60		$	195		$	180

F-8

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

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 table above reflects only the costs incurred after the date of separation, however the financial statements include aggregate costs incurred of $538 and $1,068 for the nine months ended September 30, 2005 and 2004 respectively. CNX Gas intends to adopt its own benefit plans, including a retirement plan, but has not yet adopted any such plans. Management anticipates that a retirement plan will be adopted which includes some level of a defined pension benefit as well as defined contribution feature.

CNX Gas does not expect to contribute to its pension plan in 2005.

CNX Gas does not expect to contribute to the other post employment benefit plan in 2005. CNX Gas expects to pay benefit claims as they become due.

Note 5—Income Taxes:

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


	For the Nine Months Ended September 30
	2005					2004
	Dollars			Rate		Dollars			Rate
Statutory U.S. Federal Income Tax Rate	$	39,751		35.0	%	$	35,666		35.0	%
Net Effect of State Income Tax		4,793		4.2	%		4,382		4.3	%
Effect of tax depletion in excess of tax basis		(261	)	(0.2	)%		—		—
Other		(295	)	(0.3	)%		(200	)	(0.2	)%

Income Tax Expense/Effective Rate	$	43,988		38.7	%	$	39,848		39.1	%

CNX Gas is included in the consolidated federal income tax return of its majority shareholder, 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 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. The effective tax rate for the nine months ended September 30, 2005 and 2004 was calculated using the annual effective rate projection on recurring earnings.

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 its trade accounts receivable to CNX Funding on a monthly basis at a discount. For the nine months ended September 30, 2005 and 2004, $169,939 and $207,237, respectively, of CNX Gas’ receivables were sold to CNX Funding. CNX Gas discontinued this arrangement with CONSOL Energy as of the date of separation and therefore no receivables were sold at September 30, 2005. At December 31, 2004, $28,158 were removed from CNX Gas’ receivables balance.

F-9

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

These transactions resulted in a loss of $198 and $1,327 for the three months and nine months ended September 30, 2005, respectively. These transactions resulted in a loss of $487 and $1,377 for the three months and nine months ended September 30, 2004, respectively.

Note 7—Property, Plant & Equipment:


	September 30, 2005			December 31, 2004
Surface Lands	$	23,893		$	18,240
Mineral Interests		55,621			55,620
Wells and Related Equipment		144,202			111,205
Intangible Drilling Costs		293,232			263,403
Gathering Assets		320,420			319,680
Gas Well Plugging		7,376			3,217
Other		36			74

Total Property, Plant and Equipment		844,780			771,439
Accumulated Depreciation		(155,989	)		(130,563	)

Property, Plant and Equipment Net	$	688,791		$	640,876

Note 8—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.

In 1999, CNX Gas was named in a suit brought by a group of royalty owners. 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. 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 methodology for calculating deductions from the settled case. CNX Gas management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

F-10

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County to date. In addition, Buchanan County filed an action in the Circuit Court of Buchanan County seeking a declaratory judgment declaring that CNX Gas is not entitled to take any deductions from the fair market value of the gas in computing the license payments due Buchanan County, to which action CNX Gas filed a demurrer. CNX Gas has estimated the probable outcome of this situation and reflected the estimate in other liabilities on the balance sheet. CNX Gas management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

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.

On August 22, 2005, CNX Gas obtained the issuance of a letter of credit to East Tennessee Natural Gas, LLC in the amount of $4,863. This letter of credit is 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.

CNX Gas has issued miscellaneous surety bonds, primarily gas well plugging bonds, totaling $649. CNX Gas guarantees the performance of these obligations.

Note 9—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 its operations and makes business decisions.

Segment results for the three months ended September 30, 2005 are:


	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	79,334	$	4,664	$	—	$	83,998	$	—		$	83,998
Sales—related parties		1,908		18		—		1,926		—			1,926
Sales—purchased gas		88,288		—		—		88,288		—			88,288
Other revenue		1,796		10		294		2,100		—			2,100
Intersegment revenues		—		—		12,424		12,424		(12,424	)		—

Total Revenue and Other Income	$	171,326	$	4,692	$	12,718	$	188,736	$	(12,424	)	$	176,312

Earnings Before Income Taxes	$	38,157	$	471	$	4,187	$	42,815	$	—		$	42,815	(A)

Segment assets	$	483,635	$	29,858	$	312,828	$	826,321	$			$	826,321	(B)

Depreciation, depletion and amortization	$	4,871	$	923	$	2,877	$	8,671	$	—		$	8,671

Capital expenditures	$	26,770	$	6,152	$	643	$	33,565	$	—		$	33,565

F-11

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

(A)	Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($88).

(B)	Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $49,850.

Segment results for the three months ended September 30, 2004 are:


	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	66,465	$	1,944	$	—	$	68,409	$	—		$	68,409
Sales—related parties		974		19		—		993		—			993
Sales—purchased gas		49,349		—		—		49,349		—			49,349
Other revenue		1,955		20		255		2,230		—			2,230
Intersegment revenues		—		—		12,223		12,223		(12,223	)		—

Total Revenue and Other Income	$	118,743	$	1,983	$	12,478	$	133,204	$	(12,223	)	$	120,981

Earnings Before Income Taxes	$	27,936	$	133	$	2,920	$	30,989	$	—		$	30,989	(C)

Segment assets	$	377,136	$	17,689	$	287,183	$	682,008	$	—		$	682,008	(D)

Depreciation, depletion and amortization	$	5,400	$	187	$	2,635	$	8,222	$	—		$	8,222

Capital expenditures	$	21,725	$	2,997	$	5	$	24,727	$	—		$	24,727

(C)	Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($731).

(D)	Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $45,909.

Segment results for the nine months ended September 30, 2005 are:


	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	212,626	$	11,311	$	—	$	223,937	$	—		$	223,937
Sales—related parties		5,280		45		—		5,325		—			5,325
Sales—purchased gas		157,545		—		—		157,545		—			157,545
Other revenue		5,793		40		794		6,627		—			6,627
Intersegment revenues		—		—		35,596		35,596		(35,596	)		—

Total Revenue and Other Income	$	381,244	$	11,396	$	36,390	$	429,030	$	(35,596	)	$	393,434

Earnings Before Income Taxes	$	104,404	$	415	$	8,757	$	113,576	$	—		$	113,576	(E)

Segment assets	$	483,635	$	29,858	$	312,828	$	826,321	$	—		$	826,321	(F)

Depreciation, depletion and amortization	$	15,100	$	2,151	$	8,632	$	25,883	$	—		$	25,883

Capital expenditures	$	57,769	$	11,694	$	744	$	70,207	$	—		$	70,207

F-12

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

(E)	Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($220).

(F)	Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $49,850.

Segment results for the nine months ended September 30, 2004 are:


	Central Appalachia and Tennessee		Northern Appalachia		Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	182,289	$	5,362	$	—	$	187,651	$	—		$	187,651
Sales—related parties		20,516		19		—		20,535		—			20,535
Sales—purchased gas		65,419		—		—		65,419		—			65,419
Other revenue		4,352		56		660		5,068		—			5,068
Intersegment revenues		—		—		36,395		36,395		(36,395	)		—

Total Revenue and Other Income	$	272,576	$	5,437	$	37,055	$	315,068	$	(36,395	)	$	278,673

Earnings Before Income Taxes	$	92,800	$	464	$	8,639	$	101,903	$	—		$	101,903	(G)

Segment assets	$	377,136	$	17,689	$	287,183	$	682,008	$			$	682,008	(H)

Depreciation, depletion and amortization	$	15,742	$	458	$	7,903	$	24,103	$	—		$	24,103

Capital expenditures	$	54,454	$	4,408	$	1,169	$	60,031	$	—		$	60,031

(G)	Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($1,882).

(H)	Central Appalachia and Tennessee segment includes investments in unconsolidated equity affiliates of $45,909.

Note 10—Recent Accounting Pronouncements:

F-13

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

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 is currently evaluating the impact of unvested stock options outstanding and plans to adopt the provisions of this statement January 1, 2006.

F-14

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

September 30, 2005

(Dollars in thousands, except per share data)

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.

Note 11—Subsequent Event

In conjunction with the sale of 18.5 percent of CNX Gas on August 8, 2005, CNX Gas was released from its obligation as guarantor of CONSOL Energy’s $750 million credit facility and the 7.875% Notes due March 1, 2012 in the principal amount of approximately $250 million. In addition, the business assets which had been pledged as collateral security against this facility, the 7.875% notes and the 8.25% medium term notes due 2007 in the principal amount of approximately $45 million were released. However, as a result of entering into our new $200 million credit facility with third party commercial lenders, we and our subsidiaries executed a supplemental indenture and are again guarantors of the 7.875% notes. Based on its discussions with a number of the noteholders, 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% noteholders for the release and, consequently, we will remain guarantors of the 7.875% Notes.

F-15

Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, stockholder’s equity and cash flows present fairly, in all material respects, the financial position of CNX Gas Corporation and its subsidiaries (CNX Gas), a wholly-owned subsidiary of CONSOL Energy Inc., at December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 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 6 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

July 5, 2005, except for Earnings Per Share in Note 1, as to which the date is August 11, 2005

F-16

CNX GAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands)


	For the Twelve Months Ended December 31,
	2004		2003		2002
Revenue and Other Income:
Outside Sales	$	256,579	$	178,326	$	139,343
Related Party Sales		22,036		32,572		9,542
Purchased Gas Sales		112,005		—		—
Other Income		6,916		4,485		2,068

Total Revenue and Other Income		397,536		215,383		150,953
Costs and Expenses:
Lifting Costs		23,939		20,761		16,297
Gathering and Compression Costs		37,021		28,914		24,749
Royalty		32,914		24,200		12,214
Purchased Gas Costs		113,063		—		—
Other		16,274		21,771		16,169
Equity in (Earnings) Loss of Affiliates		2,423		2,932		3,312
Selling, General and Administrative		6,327		3,194		1,140
Depreciation, Depletion and Amortization		32,889		33,600		34,368

Total Costs and Expenses		264,850		135,372		108,249

Earnings Before Cumulative Effect of Change in Accounting and Income Taxes		132,686		80,011		42,704
Income Taxes		51,898		31,202		16,677

Earnings Before Cumulative Effect of Change in Accounting		80,788		48,809		26,027
Cumulative Effect of Change in Accounting For Gas Well Closing Costs (Net of Income Taxes of $1,879)		—		2,905		—

Net Income	$	80,788	$	51,714	$	26,027

Earnings per share:
Basic	$	0.66	$	0.42	$	0.21

Diluted	$	0.66	$	0.42	$	0.21

Weighted Average Number of Common Shares Outstanding:
Basic		122,896,667		122,896,667		122,896,667

Dilutive		122,988,359		122,988,359		122,988,359


Pro Forma (unaudited)
Earnings per Share:
Basic	$	0.54

Diluted	$	0.54


Weighted Average Number of Common Shares Outstanding:
Basic		150,833,334

Dilutive		150,925,026

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

F-17

CNX GAS AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(Dollars in thousands)


	December 31,
	2004			2003
ASSETS
Current Assets:
Cash and Cash Equivalents	$	3		$	4
Accounts Receivable:
Trade		700			418
Other		735			234
Deferred Taxes		8,301			21,213
Other Current Assets		6,585			43

Total Current Assets		16,324			21,912
Property and Equipment, Net		640,876			583,704
Other Assets		14,951			12,584
Derivatives		3,766			—
Investments in Equity Affiliates		47,373			46,435

TOTAL ASSETS	$	723,290		$	664,635

LIABILITIES AND STOCKHOLDER’S EQUITY
Current Liabilities:
Accounts Payable	$	24,002		$	21,405
Accrued Royalties Payable		8,701			6,089
Accrued Severance Taxes		2,337			1,614
Accrued Income Taxes		941			—
Other Accrued Liabilities		6,112			775

Total Current Liabilities		42,093			29,883
Deferred Taxes		183,624			145,725
Other Liabilities		10,202			5,623
Well Closing Liabilities		8,685			7,422
Derivatives		13,027			8,887
Postretirement Benefits Other Than Pension		3,103			2,863

Total Liabilities		260,734			200,403
Stockholder’s Equity
Retained Earnings		252,469			171,681
Capital in Excess of Par Value		215,710			297,947
Accumulated Other Comprehensive Loss		(5,623	)		(5,396	)

Total Stockholder’s Equity		462,556			464,232

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	723,290		$	664,635

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

F-18

CNX GAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(Dollars in thousands)


	Capital in Excess of Par Value			Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Total Stockholder’s Equity
Balance at December 31, 2001	$	336,925		$	93,940	$	—		$	430,865
Net Income		—			26,027		—			26,027
Capital Contribution From Parent		13,548			—		—			13,548
Gas Cash Flow Hedge (Net of $1,179 tax)		—			—		(1,823	)(a)		(1,823	)


Balance at December 31, 2002		350,473			119,967		(1,823	)		468,617
Net Income		—			51,714		—			51,714
Return of Capital to Parent		(52,526	)		—		—			(52,526	)
Gas Cash Flow Hedge (Net of $2,312 tax)		—			—		(3,573	)(b)		(3,573	)

Balance at December 31, 2003		297,947			171,681		(5,396	)		464,232
Net Income		—			80,788		—			80,788
Return of Capital to Parent		(82,237	)		—		—			(82,237	)
Gas Cash Flow Hedge (Net of $146 tax)		—			—		(227	)(c)		(227	)

Balance at December 31, 2004	$	215,710		$	252,469	$	(5,623	)	$	462,556

(a)	Represents the unrealized holding loss during the period.

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

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

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

F-19

CNX GAS AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)


	For the Twelve Months Ended December 31,
	2004			2003			2002
Operating Activities:
Net Income	$	80,788		$	51,714		$	26,027
Adjustments to Reconcile Net Income to Net Cash (Used In) Provided By Operating Activities:
Cumulative Effect of Change in Accounting Principle, net of tax		—			(2,905	)		—
Depreciation, Depletion and Amortization		32,889			33,600			34,368
Income Taxes		941			—			—
Deferred Income Taxes		50,957			31,202			16,677
Equity in Loss of Affiliates		2,423			2,932			3,312
Changes in Operating Assets:
Accounts Receivable		(783	)		16,576			(3,264	)
Other Current Assets		(6,542	)		312			1,506
Changes in Other Assets		(2,367	)		(5,719	)		(5,670	)
Changes in Operating Liabilities:
Accounts Payable		2,597			13,759			4,474
Other Current Liabilities		8,672			1,407			1,359
Changes in Other Liabilities		5,583			(236	)		9,701
Other		192			491			153

Net Cash Provided by Operating Activities		175,350			143,133			88,643

Investing Activities:
Capital Expenditures		(89,753	)		(83,869	)		(61,705	)
Investment in Equity Affiliates		(3,361	)		(7,169	)		(39,767	)
Proceeds from Sales of Assets		—			433			—

Net Cash Used in Investing Activities		(93,114	)		(90,605	)		(101,472	)

Financing Activities:
Receipt from (Payment to) Parent		(82,237	)		(52,526	)		12,831

Net Cash (Used in) Provided by Financing Activities		(82,237	)		(52,526	)		12,831
Net Increase (Decrease) in Cash and Cash Equivalents		(1	)		2			2
Cash and Cash Equivalents at Beginning of Period		4			2			—

Cash and Cash Equivalents at End of Period	$	3		$	4		$	2

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

F-20

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands)

Note 1—Significant Accounting Policies:

Nature of Operations

CNX Gas is a natural gas producer with emphasis on Appalachian area natural gas drilling, transportation and sales. CNX Gas is one of the largest U.S. producers of coalbed methane, and is one of the largest owners of proved natural gas reserves in the Appalachian Basin. CNX Gas transports gas from wells it owns, and those operated by others, to interstate pipelines by way of the Cardinal States Gathering Pipeline and the Coalfield Pipeline. The Company finances a substantial portion of its drilling activities through existing operations.

CNX Gas represents the wholly-owned gas operations of CONSOL Energy Inc. (CONSOL Energy). These financial statements reflect the activities of CONSOL Energy’s gas operations on a combined basis. As of December 31, 2004, CNX Gas was not a legal entity and, therefore, there were no outstanding shares of common stock or earnings per share information. CONSOL Energy is a publicly traded company (trading under the symbol CNX on the NYSE) operating in the energy sector.

Principles of Consolidation

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

CNX Gas 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	%

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 closing liabilities, proved gas reserve estimates and charges from CONSOL Energy for corporate overhead and employee benefit related obligations.

Cash and Cash Equivalents

Cash management for CNX Gas is conducted by CONSOL Energy.

Amounts of receivables/payables outstanding at December 31, 2004 and 2003 are considered by CNX Gas to be a capital contribution or a return of capital from CONSOL Energy. No interest has been charged or paid to CNX Gas under this arrangement.

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.

F-21

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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. Reserves for uncollectible amounts were not material in the periods presented.

Property, Plant and Equipment

CNX Gas follows the successful efforts method of accounting for gas properties. Accordingly, costs of property acquisitions, successful exploratory wells, development wells and related support equipment and facilities are capitalized. Costs of unsuccessful exploratory wells are expensed when such wells are determined to be non-productive, or if the determination cannot be made after finding sufficient quantities of reserves to continue evaluating the viability of the project. Property carrying costs are charged to expense when incurred. CNX Gas periodically assesses unproved and proved properties to determine whether there has been a decline in value. If such a decline is indicated, a loss is recognized.

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 amortizes proved gas properties, which include intangible drilling and development costs, tangible well equipment and leasehold 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. CNX Gas computes depreciation on property and equipment, other than oil and gas properties but including assets leased under capital leases, using the straight-line method over the estimated economic lives or lease terms, which range from 7-40 years.

Impairment of Long-lived Assets

Impairment of long-lived assets is recorded when indicators of impairment are present and the undiscounted cash flows estimated to be generated by those assets are less than the assets’ carrying value. The carrying value of the assets is then reduced to their estimated fair value which is usually measured based on an estimate of future discounted cash flows. 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 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.

F-22

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Multi-Employer Retirement Plan

CNX Gas provides a non-contributory defined benefit pension plan covering substantially all of their employees through CONSOL. The plan is administered by CONSOL Energy, and costs are allocated to CNX Gas based on their portion of active salary labor dollars.

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 Closing 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 closure 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.

CNX Gas also has a gas-balancing agreement with TCO Interstate Pipeline. This agreement is in accordance with the Council of Petroleum Accountants Societies (COPAS) 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 requesting adjustments to contracted 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 imbalance amounts, for both volumes and dollars, were insignificant at December 31, 2004 and 2003.

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 gas buy/sells. These revenues and expenses are recorded gross and recognized immediately in earnings.

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

F-23

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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 a related royalty fee.

Contingencies

CNX Gas and its 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.

Accounting for 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 in 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. 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.

Recent Accounting Pronouncements

On December 15, 2004, the Financial Accounting Standards Board (FASB) released its final revised standard entitled SFAS 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. SFAS No. 123R is effective for public companies as of the beginning of the first annual reporting period that begins after June 15, 2005. No options for CNX Gas are outstanding at December 31, 2004, therefore, no immediate impact from adoption is expected.

On November 30, 2004, the FASB ratified EITF Issue No. 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations” (EITF 03-13). To qualify as a discontinued operation, paragraph 42 of SFAS No. 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. EITF 03-13 provides guidance on how to interpret and

F-24

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

apply the criteria in paragraph 42A (elimination of cash flows) and paragraph 42B (no significant continuing involvement) of SFAS No. 144. EITF 03-13 is to be effective for all periods beginning after December 15, 2004. Previously reported operating results related to disposal transactions initiated within an enterprise’s fiscal year that includes November 30, 2004 may be reclassified to reflect the consensus. We do not expect this guidance to have a financial impact on CNX Gas.

On October 13, 2004, the FASB ratified 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 SFAS No. 131 when determining whether operating segments that do not meet the quantitative thresholds may be aggregated in accordance with paragraph 19 of SFAS 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.

The American Jobs Creation Act of 2004 was signed into law in October 2004 (the Act) and has several provisions that impact energy companies, including a deduction related to qualified production activities that includes CNX Gas’ oil and gas extraction activities. For the tax years 2005-2006, the deduction will equal 3% of the lessor of qualified production activities income or taxable income. The percentage rises to 6% in 2007-2009 and to 9% in 2010 and after. Pursuant to FASB guidance, the deduction will be treated as a special deduction that will reduce CNX Gas’ estimate of its annual effective tax rate in the period in which the deduction is claimed on its tax return. The impact of this provision on 2005 and later years is being evaluated.

In April 2005, the FASB issued FSP No. FAS 19-1 “Accounting for Suspended Well Costs” (FSP FAS 19-1). FSP FAS 19-1 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. When a classification of proved reserves cannot yet be made, FSP FAS 19-1 allows exploratory well costs to continue to be capitalized when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. CNX Gas’ current policy is in accordance with FSP FAS 19-1. FSP FAS 19-1 also provides for certain disclosures to be made regarding capitalized exploratory well costs. As of December 31, 2004, CNX Gas had an immaterial amount capitalized for exploratory well costs pending determination of proved reserves and an immaterial amount in capitalized costs for exploratory wells where drilling had been completed for a period greater than one year.

F-25

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Earnings Per Share

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. In August 2005, a Registration Statement on Form S-1 was filed with the SEC with respect to those shares, however the registration statement has not yet been declared effective and the shares may not be offered or sold in the United States absent registration or an applicable exemption from registration. The proceeds (approximately $420,167 including the additional 3.6 million shares) were used to pay a special dividend to CONSOL Energy. In addition, CONSOL Energy paid approximately $6,000 in expenses related to this transaction.

Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the period. However, because CNX Gas was formed as a subsidiary of CONSOL Energy, the number of shares issued upon formation is utilized for all 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.


	For the Twelve Months Ended December 31,
	2004		2003		2002
Net Income	$	80,788	$	51,714	$	26,027

Weighted Average Number of Common Shares Outstanding:
Basic		122,896,667		122,896,667		122,896,667
Effect of stock options		91,692		91,692		91,692

Dilutive		122,988,359		122,988,359		122,988,359


Earnings per share:
Basic	$	0.66	$	0.42	$	0.21

Diluted	$	0.66	$	0.42	$	0.21

F-26

CNX GAS 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, 2004
Net Income	$	80,788

Pro Forma
Weighted Average Number of Common Shares Outstanding:
Basic		150,833,334
Effect of stock options		91,692

Dilutive		150,925,026

Earnings per share:
Basic	$	0.54

Diluted	$	0.54

Note 2—Transactions with Related Parties:

CNX Gas sells gas to CONSOL Energy and Buchanan Generation, which CNX Gas has a 50% interest, on a basis reflecting the monthly average price received by CNX Gas from third party sales. 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 an arms-length transaction. The following table reflects the amounts of these transactions:


	For the Twelve Months Ended December 31,
	2004		2003		2002
Sales of Gas-Related Party	$	22,036	$	32,572	$	9,542
Supply Purchases	$	137	$	89	$	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. This arrangement allows CNX Gas to obtain funds from CONSOL Energy at any time. These amounts are considered to be a capital contribution from, or a return of capital to, CONSOL Energy. No interest has been charged or paid under this arrangement.

General and administrative expenses contain fees of $6,327, $3,194 and $1,140 for the twelve months ended December 31, 2004, 2003 and 2002, 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.

F-27

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

and, therefore, benefits from this drilling activity, although it is not burdened with the cost to drill gob wells. CNX Gas is responsible for the costs incurred to gather and deliver the gob gas to market. All gob well drilling costs are borne by Consol Energy and only the collection and processing costs are reflected in CNX Gas’s historical financial statements and our master cooperation and safety agreement with CONSOL Energy retains this cost structure after our separation from CONSOL Energy.

Employees participate in a non-contributory defined benefit pension plan administered by CONSOL Energy. Benefits for this plan are based primarily on years of service and employee’s pay near retirement. CNX Gas’ allocation of the pension expense under this plan was $1,433, $1,035 and $449 for the twelve months ended December 31, 2004, 2003 and 2002, respectively. CONSOL Energy’s allocation of the expense for this plan is based on the percentage of CNX Gas’ active employee salary wages compared to the total active employee salary wages covered by the plan.

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 $337, $294 and $286 for the twelve months ended December 31, 2004, 2003 and 2002, 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 $140, $152 and $158 for the twelve months ended December 31, 2004, 2003 and 2002, 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 it operates and is self-insured for these claims in West Virginia and Virginia. Workers’ compensation expense for these benefits was $22, $11 and $8 for the twelve months ended December 31, 2004, 2003 and 2002, 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, 2004, 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 AEP Energy Services to unconditionally guarantee the full and prompt payment of all obligations, up to $15,000 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.

F-28

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

•

CONSOL Energy is the guarantor of the agreement dated May 26, 2004 between CNX Gas Company 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 days 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.

The historical financial statements of CNX Gas 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,
	2004		2003		2002
Other Royalty Income	$	5,726	$	3,968	$	2,051
Third Party Gathering Revenue		1,109		440		—
Sales of Oil Production		54		61		24
Miscellaneous		27		16		(7	)

Total Other Income	$	6,916	$	4,485	$	2,068

Note 4—Postretirement Benefits Other Than Pension:

CNX Gas provides medical and life insurance benefits to retired employees under CONSOL Energy’s Employee Retirement Plan (the Plan). Prior to August 1, 2003, substantially all employees became eligible for these benefits if they had ten years of company service and attained age 55. Effective August 1, 2003, the Plan was amended, such that, the base eligibility was changed to age 55 with 20 years of service. In addition, effective January 1, 2004, a medical plan cost sharing arrangement with all salaried employees and retirees was adopted.

F-29

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

These participants will now contribute a minimum of 20% of medical plan operating costs. Contributions may be higher, dependent on either years of service, or a combination of age and years of service at retirement. Prospective annual cost increases of up to 6% will be shared 80% by CNX Gas and 20% by the participants. Annual cost increases in excess of 6% will be the sole responsibility of the participant. Also, any salaried or non-represented hourly employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of one thousand dollars per year of service at retirement. The medical plans contain certain cost sharing and containment features, such as deductibles, coinsurance, health care networks and coordination with Medicare.

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


	At December 31,
	2004			2003
Change in benefit obligation:
Benefit obligation at beginning of period	$	2,996		$	3,864
Service costs		131			203
Interest costs		163			261
Actuarial (gain) loss		(464	)		(50	)
Plan amendments		—			(1,282	)

Benefit obligation at end of period	$	2,826		$	2,996

Funded Status:
Underfunded obligation	$	2,826		$	2,996
Unrecognized prior service credit		1,112			1,230
Unrecognized net actuarial loss		(829	)		(1,357	)

Accrued benefit costs	$	3,109		$	2,869

The components of net periodic benefit costs are as follows:


	For the Twelve Months Ended December 31,
	2004			2003			2002
Components of Net Periodic Benefit Costs:
Service costs	$	131		$	203		$	177
Interest costs		163			261			198
Amortization of prior service costs (credit)		(117	)		(80	)		(24	)
Recognized net actuarial loss (gain)		63			95			41

Benefit costs	$	240		$	479		$	392

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 our postretirement 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 postretirement benefit obligation. These effects are included in the actuarial (gain) loss line in the tables above.

F-30

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Assumptions:

The weighted-average discount rate assumptions used to determine benefit obligations were 6.00% at both December 31, 2004 and 2003. The weighted-average discount rate assumptions used to determine net periodic benefit costs were 6.00%, 6.75% and 7.25% for the twelve months ended December 31, 2004, 2003 and 2002, respectively.

The assumed health care cost trend rates are as follows:


	December 31,
	2004		2003		2002
Health care cost trend rate for next year	10.00	%	10.00	%	8.00	%
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		2010		2008

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	$	344	$	(255	)
Effect on accumulated postretirement benefit obligation		3,081		(2,593	)

Cash Flows:

CNX Gas intends to pay other postemployment benefit claims as they are due. The following benefit payments and subsidy receipts, which reflect future service, are expected to be paid:


	Other Benefits
	Payments		Subsidy
2005	$	6	$	—
2006		13		—
2007		24		—
2008		39		—
2009		57		—
Year 2010-2014		803		6

Note 5—Income Taxes:

Income taxes (benefits) provided on earnings consisted of:


	For the Twelve Months Ended December 31,
	2004		2003		2002
Current:
U.S. Federal	$	941	$	—	$	—
Deferred:
U.S. Federal		45,297		27,799		14,858
U.S. State		5,660		3,403		1,819

Total Income Tax Expense	$	51,898	$	31,202	$	16,677

F-31

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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


	December 31,
	2004			2003
Deferred Tax Assets:
Well Closing	$	3,411		$	2,915
Federal Net Operating Loss		3,326			19,795
State Net Operating Loss		407			2,421
Other postemployment benefits		1,219			1,125
Minimum Tax Credit		941			—
Other Assets		3,627			3,485

Total Deferred Tax Assets		12,931			29,741
Deferred Tax Liabilities:
Property, Plant and Equipment		(180,573	)		(147,414	)
Investment in Equity Affiliates		(7,681	)		(6,839	)

Total Deferred Tax Liabilities		(188,254	)		(154,253	)

Net Deferred Tax Liabilities	$	(175,323	)	$	(124,512	)

CNX Gas has regular net operating loss carryforwards that will be used to offset future regular federal tax income, within the next five years. These net operating losses begin to expire in 2022.

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,
	2004					2003					2002
	Dollars			Rate		Dollars			Rate		Dollars			Rate
Statutory U.S. Federal Income Tax Rate	$	46,440		35.0	%	$	28,004		35.0	%	$	14,946		35.0	%
Net Effect of State Income Tax		5,659		4.3	%		3,403		4.3	%		1,819		4.3	%
Other		(201	)	(0.2	)%		(205	)	(0.3	)%		(88	)	(0.2	)%

Income Tax Expense/ Effective Rate	$	51,898		39.1	%	$	31,202		39.0	%	$	16,677		39.1	%

Note 6—Changes in Accounting for Gas Well Closing 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 closing. 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 upon the adoption of this statement was a gain of $2,905, net of a tax cost of approximately $1,879. The cumulative effect adjustment was recognized in the three months ended March 31, 2003. Net income for the twelve months ended December 31, 2002 would not materially differ if this statement had been adopted on January 1, 2002. The obligation for asset retirements is included in Well Closing Liabilities on the balance sheet.

F-32

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

The reconciliation of changes in the asset retirement obligations at December 31, 2004 and 2003 is as follows:


	As of December 31,
	2004			2003
Balance at beginning of period	$	7,422		$	7,513
Accretion expense		525			450
Payments		(394	)		(541	)
Revisions in estimated cash flows		1,132			—

Balance at end of period	$	8,685		$	7,422

Note 7—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, sells the majority of its trade accounts receivable to CNX Funding on a monthly basis. For the years ended December 31, 2004 and 2003, $284,340 and $191,760, respectively of CNX Gas’ receivables were sold to CNX Funding. At December 31, 2004 and 2003, respectively, $28,158 and $19,708 have been removed from CNX Gas’ trade receivable balance. These transactions resulted in discounts of $1,964 and $1,147 in the year ended December 31, 2004 and 2003, respectively.

Note 8—Other Current Assets:


	As of December 31,
	2004		2003
Gas Firm Transportation	$	4,431	$	—
Land Option Deposit		1,200		—
Other		954		43

Total Other Current Assets	$	6,585	$	43

Note 9—Property, Plant and Equipment:


	As of December 31,
	2004			2003
Surface Lands	$	18,240		$	14,050
Mineral Interests		55,620			55,431
Wells and related Equipment		111,205			89,657
Intangible Drilling		263,403			225,269
Gathering Assets		319,680			294,813
Gas Well Closing		3,217			2,084
Other		74			74

Total Property, Plant and Equipment		771,439			681,378
Accumulated Depreciation		(130,563	)		(97,674	)

Property and equipment, net	$	640,876		$	583,704

F-33

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 10—Other Accrued Liabilities:


	As of December 31,
	2004		2003
Gas Firm Transportation	$	4,780	$	—
Current Portion of Postretirement Benefits Other than Pensions		6		6
Other		1,326		769

Total Other Accrued Liabilities	$	6,112	$	775

Note 11—Leases:

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


	Annual Operating Leases
2005	$	560
2006		372
2007		251
2008		129
2009		128
Thereafter		1,034

Total minimum lease payments	$	2,474

Rental expense under operating leases was $1,566, $2,563 and $2,008 for the twelve months ended December 31, 2004, 2003 and 2002, respectively.

Note 12—Supplemental Cash Flow Information:

CNX Gas had no payments made or received for interest or income taxes in the periods presented.


	December 31,
	2004			2003			2002
Accounting for mine closing, reclamation and gas well closing costs (Note 6)
Change in assets	$	(500	)	$	(6,450	)	$	—
Change in liabilities	$	(500	)	$	(6,450	)	$	—

Note 13—Concentration of Credit Risk:

CNX Gas markets pipeline quality 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.

F-34

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

During the twelve months ended December 31, 2004, 2003 and 2002, 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,
	2004		2003		2002
Dominion	22	%	8	%	—
American Electric Power	17	%	24	%	42	%
Conoco	13	%	51	%	49	%
Allegheny Energy	—		14	%	6	%

Note 14—Derivative Instruments:

CNX Gas holds or purchases derivative financial instruments for purposes other than trading. The net fair values of the outstanding instruments are liabilities of $9,261 and $8,887 at December 31, 2004 and 2003, respectively.

Cash flow hedges for natural gas were entered into to convert the market prices related to 2005, 2004 and 2003 anticipated sales of natural gas to fixed prices. Any gains or losses related to these derivative instruments will be recognized when the sale of the natural gas occurs. There was no ineffectiveness in 2004, 2003 and 2002 related to these hedging strategies.

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 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 2004, 2003 or 2002.

CNX Gas did not have any derivatives designated as fair value hedges in 2004, 2003 and 2002.

Note 15—Commitments and Contingent Liabilities:

F-35

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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 $3,500 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 its financial position, results of operations, or cash flows.

CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2001. CNX Gas has filed appropriate returns and paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County to date. In addition, the County has questioned the calculation of our license taxes for subsequent periods. CNX Gas has estimated the probable outcome of this situation and reflected the estimate in other liabilities on the balance sheet. CNX Gas management believes that the final resolution of this matter will not have a material effect on its financial position, results of operations, or cash flows.

On October 7, 2004, CNX Gas obtained the issuance of a letter of credit to Columbia Gas Transmission Corp in the amount of $2,500. 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 has issued miscellaneous surety bonds, primarily gas well plugging bonds, totaling $486. CNX Gas guarantees the performance of these obligations.

Note 16—Segment Information:

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	(A)

Segment assets	$	412,839	$	20,197	$	281,953	$	714,989	$	8,301		$	723,290	(B)

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

F-36

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

(A)	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.

(B)	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	(C)

Segment assets	$	370,543	$	11,617	$	261,262	$	643,422	$	21,213		$	664,635	(D)

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

(C)	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.

(D)	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.

F-37

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Industry segment results for the twelve months ended December 31, 2002 are:


	Central Appalachia and Tennessee		Northern Appalachia			Gathering		Total Gas		Corporate Adjustments & Eliminations			Consolidated
Sales—outside	$	137,481	$	1,862		$	—	$	139,343	$	—		$	139,343
Sales—related parties		9,542		—			—		9,542		—			9,542
Other revenue		2,046		22			—		2,068		—			2,068
Intersegment revenues		—		16			60,316		60,332		(60,332	)		—

Total Revenue and Other Income	$	149,069	$	1,900		$	60,316	$	211,285	$	(60,332	)	$	150,953

Earnings (Loss) Before Income Taxes	$	36,838	$	(1,024	)	$	6,894	$	42,708	$	(4	)	$	42,704	(E)

Segment assets	$	331,181	$	9,536		$	257,519	$	598,236	$	—		$	598,236	(F)

Depreciation, depletion and amortization	$	25,395	$	303		$	8,670	$	34,368	$	—		$	34,368

Capital expenditures	$	54,260	$	2,632		$	4,813	$	61,705	$	—		$	61,705

(E)	Central Appalachia and Tennessee segment includes equity in earnings (loss) of unconsolidated affiliates of ($3,312). Corporate Adjustments and Eliminations include miscellaneous corporate charges not allocated to individual segments.

(F)	Central Appalachia and Tennessee segment includes investments in unconsolidated affiliates of $42,198.

F-38

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Note 17—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,
	2004			2003
Surface Lands	$	18,240		$	14,050
Mineral Interests		55,620			55,431
Wells and related Equipment		111,205			89,657
Intangible Drilling		263,403			225,269
Gathering Assets		319,680			294,813
Gas Well Closing		3,217			2,084
Other		74			74

Total Property, Plant and Equipment		771,439			681,378
Accumulated Depreciation		(130,563	)		(97,674	)

Net Capitalized Costs	$	640,876		$	583,704

Proportionate Share of Gas Producing Net Property, Plant and Equipment of Unconsolidated Equity Affiliates	$	15,239		$	14,350

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


	For the Twelve Months Ended December 31,
	2004				2003				2002
	Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates		Consolidated Operations		Equity Affiliates
Property acquisitions	$	4,190	$	111	$	7,640	$	187	$	4,660	$	2,018
Development		77,478		—		77,801		—		49,869		—
Exploration		5,596		2,902		5,997		4,661		9,159		7,302

Total	$	87,264	$	3,013	$	91,438	$	4,848	$	63,688	$	9,320

(*)	Includes costs incurred whether capitalized or expensed

F-39

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

Results of Operations:


	For the Twelve Months Ended December 31,
	2004						2003						2002
	Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates			Consolidated Operations			Equity Affiliates
Production Revenue	$	278,615		$	1,587		$	210,898		$	595		$	148,885		$	783
Purchased Gas Revenue		112,005			1,120			—			152			—			—
Other Revenue		6,916			152			4,485			372			2,068			120

Total Revenue		397,536			2,859			215,383			1,119			150,953			903

Lifting Costs		23,939			474			20,761			434			16,297			224
Gathering Costs		37,021			172			28,914			170			24,749			446
Royalty Expense		32,914			246			24,200			96			12,214			457
Other Production Costs		16,274			1,153			21,771			1,294			15,915			2,608
Purchased Gas Costs		113,063			1,044			—			351			—			—
DD&A		32,889			918			33,600			319			34,368			145

Total Costs		256,100			4,007			129,246			2,664			103,543			3,880

Pre-tax Operating Income		141,436			(1,148	)		86,137			(1,545	)		47,410			(2,977	)
Income Taxes		55,556			(451	)		33,835			(607	)		18,632			(1,170	)

Results of Operations excluding Corporate and Interest Costs	$	85,880		$	(697	)	$	52,302		$	(938	)	$	28,778		$	(1,807	)


Net Reserve Quantity (Million Cubic Feet)(1)
Beginning Reserves		1,002,800			1,581			959,946			559			1,016,577			6,802
Revisions		33,539			—			17,484			(200	)		(50,907	)		—
Extensions and Discoveries		53,870			1,006			69,710			1,303			28,743			559
Production		(49,674	)		(202	)		(44,340	)		(81	)		(41,068	)		(201	)
Purchases of Reserves In-Place		1,868			—			—			—			6,601			—
Sales of Reserves In-Place		—			—			—			—			—			(6,601	)

Ending Reserves		1,042,403			2,385			1,002,800			1,581			959,946			559

Proved Developed Reserves:
Beginning of Period		352,935			843			329,687			559			357,341			6,802

End of Period		395,152			1,489			352,935			843			329,687			559

*	Proved developed and 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 (97.3%), West Virginia (0.8%) 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

F-40

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

likely to change as future information becomes available. Proved oil and gas reserves are estimated quantities of natural gas and coalbed methane 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.

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,
	2004			2003			2002
Future Cash Flows:
Revenues	$	6,337,257		$	5,792,348		$	4,615,330
Production costs		(1,453,364	)		(1,314,691	)		(1,311,172	)
Development costs		(265,540	)		(307,075	)		(283,290	)
Income tax expense		(1,745,782	)		(1,461,785	)		(983,172	)

Future Net Cash Flows		2,872,571			2,708,797			2,037,696
Discounted to present value at a 10% annual rate		(1,843,033	)		(1,697,611	)		(1,302,515	)

Total standardized measure of discounted net cash flows	$	1,029,538		$	1,011,186		$	735,181

The above table excludes CNX Gas’ interest in equity affiliates due to the immateriality of these ventures. As these ventures develop separate information will be provided.

F-41

CNX GAS AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS—(Continued)

(Dollars in thousands)

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


	December 31,
	2004			2003			2002
Balance at Beginning of Period	$	1,011,186		$	735,181		$	345,826
Net changes in sales prices and production costs		262,723			1,036,699			1,974,411
Sales net of production costs		(219,937	)		(151,499	)		(65,346	)
Net change due to revisions in quantity estimates		364,456			287,993			(34,814	)
Development costs incurred, previously estimated		87,274			80,455			42,705
Changes in estimated future development costs		(45,739	)		(104,240	)		(41,090	)
Net change in future income taxes		(283,997	)		(478,613	)		(739,520	)
Accretion of discount and other		(146,428	)		(394,790	)		(746,991	)

Total Discounted Cash Flow at End of Period	$	1,029,538		$	1,011,186		$	735,181

Note 18—Selected Quarterly Data (Unaudited):


	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 Segment Operating Income	$	36,800	$	34,114	$	30,989	$	30,783

Net Income	$	22,408	$	20,775	$	18,872	$	18,733


	Three Months Ended
	March 31, 2003		June 30, 2003		September 30, 2003		December 31, 2003
Total Revenue and Other Income	$	53,673	$	52,726	$	52,455	$	56,529

Total Costs and Expense	$	35,952	$	34,256	$	33,896	$	31,268

Total Segment Operating Income	$	17,721	$	18,470	$	18,559	$	25,261

Earnings Before Cumulative Effect	$	10,810	$	11,267	$	11,321	$	15,411

Net Income	$	13,715	$	11,267	$	11,321	$	15,411

Note 19—Subsequent Event

On June 21, 2005, the Board of Directors of CONSOL Energy authorized the incorporation of CNX Gas. On June 30, 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.

F-42

APPENDIX A

Reserve and Economic Evaluation of

Proved Reserves

Of Certain

CONSOL Energy, Inc.

Oil and Gas Interests

As of March 31, 2005

Prepared For

CONSOL Energy, Inc.

Pittsburgh, Pennsylvania

Prepared By

Schlumberger Data and Consulting Services

Pittsburgh, Pennsylvania

July 2005

A-1

Data & Consulting Services

Division of Schlumberger Technology Corporation

Schlumberger

1310 Commerce Drive

Park Ridge 1

Pittsburgh, PA 15275-1011

Tel: 412-787-5403

Fax: 412-787-2906

7	July, 2005

Mr. William Lyons

CONSOL Energy, Inc.

1800 Washington Road

Pittsburgh, PA 15241

Dear Mr. Lyons:

At the request of CONSOL Energy, Inc., Schlumberger Data & Consulting Services (DCS) has prepared a reserve and economic evaluation of certain proved oil and gas interests controlled by CNX Gas Corporation (CNX) as of March 31, 2005. Unescalated prices and costs were used for all properties contained in this evaluation. The oil and gas interests evaluated are located in four projects in Pennsylvania, Tennessee, Virginia, and West Virginia. The results of this Proved reserve evaluation are summarized in Table 1. Actual future prices may vary significantly from the prices used in this evaluation; therefore, future hydrocarbon volumes recovered and the income received from these volumes may vary significantly from those estimated in this report.

The values in the following tables may not add up arithmetically or exactly match the attached cash flows due to rounding procedures in the computer software program used to prepare the economic projections. Cash flows summarized by reserve category are included in the CNX Total attachment. Summary level cash flows by reserve category and project are included in the subsequent attachments of this report. Well count summaries are not accurate in several of the attached cash flows. The well counts contained on the summary level cash flows for the CNX Totals and Virginia coalbed methane project do not reflect the proper well counts due to the proved reserves and wells associated with the active mine operation.

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TABLE 1

ESTIMATED NET RESERVES & INCOME

CERTAIN PROVED

OIL AND GAS INTERESTS

EVALUATED FOR CONSOL ENERGY, INC.

AS OF MARCH 31, 2005


	Proved Producing Reserves	Fixed Field & Admin Cost		Gas Contract Value		Total Proved Producing Reserves	Proved Non- Producing Reserves	Proved Undeveloped Reserves	Total Proved Reserves
Remaining Reserves
Oil—MB	21.505	0.000		0.000		21.505	0.000	0.000	21.505
Gas—MMscf	500,709.219	0.000		0.000		500,709.219	19,398.023	573,170.438	1,093,277.750

Income Data (M$)
Future Gross Revenue	3,723,959.750	0.000		(56,680.449	)	3,667,279.250	144,398.484	4,214,273.000	8,025,950.500
Deductions
Operating Expense Production Tax Ad Valorem Tax Investment w/Abdn	608,191.062 109,652.289 37,291.461 24,517.248	884,053.500 0.000 0.000 0.000		172,498.203 0.000 0.000 0.000		1,664,742.750 109,652.289 37,291.461 24,517.248	16,747.139 4,331.955 1,404.325 4,940.875	627,870.375 125,574.102 40,602.297 328,581.781	2,309,360.250 239,558.359 79,298.086 358,039.875
Future Net Income	2,944,307.000	(884,053.438	)	(229,178.656	)	1,831,075.000	116,974.188	3,091,644.750	5,039,693.500
Discounted FNI @ 10%	1,266,604.625	(183,559.859	)	(154,327.766	)	928,716.812	53,344.207	855,066.188	1,837,126.875

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Data & Consulting Services

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RESERVE ESTIMATES

Virginia Coalbed Methane Project

Production data analysis methods were used to generate the performance forecasts of the coalbed methane wells located in CNX’s coalbed methane (CBM) project located in Virginia. Gas and water production data were evaluated for existing wells in each area. The primary tools used in our analysis were decline curve analysis, analogous production models, and reservoir simulation. COALGAS™, a three-dimensional, two-phase, finite-difference reservoir simulation model developed by DCS was used for the reservoir simulation. COALGAS™ was created specifically for analysis of coalbed methane wells. Reservoir descriptions were generated for wells in each area by history matching the production data from type wells in each area. For this analysis, certain reservoir properties were estimated using available well and reservoir data, and certain key reservoir properties were determined in the history matching process. The resulting reservoir descriptions were then used to forecast future production for the wells.

Basic formation properties, such as relative permeability, adsorbed gas content, net pay thickness, and gas gravity were estimated using data provided by CNX and/or from publicly available information. Specific properties that were estimated for this evaluation included initial pressures, which were calculated based on the depth of the producing intervals, and net pay thickness based on well log data from type-wells in each area. Some estimated average well properties such as adsorbed gas content, a desorption isotherm, and coal quality (ash and moisture content) were estimated using data provided by CNX for wells in each area. Other estimated average well properties such as permeability, natural fracture porosity, initial free gas saturation, and effective well drainage areas were based on an analysis of production data from individual wells.

The total proved reserves within the CNX mine area are based on development of the mine in accordance with the mine operator’s current mine development plan. The proved producing reserves are based on the currently developed frac wells, horizontal wells, gob panels, and sealed gob areas with their production volumes extended to their economic life or 65 years, whichever occurs first. The proved undeveloped reserves within the CNX mine area are based on the total calculated proved reserves minus the proved producing reserves. For wells outside of the active mine area, the proved undeveloped reserves for frac wells are based on the type-wells in each area.

Northern Appalachian Basin Coalbed Methane Project

Production data analysis methods were used to generate the performance predictions for the coalbed methane wells located in CNX’s Northern Appalachian Basin CBM project (NAPP) located in Pennsylvania and West Virginia. Gas and water production data were evaluated for existing wells in each area.

The process consisted of modeling 7 existing horizontal wells in Greene County, Pennsylvania with measured and derived reservoir parameters to establish a probable future production curve (type curve). COALGAS™, a three-dimensional, two-phase, finite-difference reservoir simulation model developed by DCS was used for the reservoir modeling. For this analysis, certain reservoir properties were estimated using available well and reservoir data, and certain key reservoir properties were determined in the history matching process. The resulting reservoir descriptions were then used to forecast future production for the wells. The derived curve was then compared to decline curves attained from up to three years of production data and gas in place estimates.

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properties that were estimated for this evaluation included initial pressures, which were calculated based on the depth of the producing intervals, and net pay thickness based on well log data from type-wells in each area. Some estimated average well properties such as adsorbed gas content, a desorption isotherm, and coal quality (ash and moisture content) were estimated using data provided by CNX for wells in each area. Other estimated average well properties such as permeability, natural fracture porosity, initial free gas saturation, and effective well drainage areas were based on an analysis of production data from individual wells.

Outside of the seven well horizontal modeling areas, the type curve was adjusted as a function of gas in place. Gas in place was calculated as a function of elevation change from the model area and coal thickness. Seam elevation and thickness were provided in the form of maps from CNX.

Triana JV and Knox Energy Conventional Gas Projects

Conventional decline curve analysis and production data analysis methods were used to estimate the remaining future producing reserves for the Triana JV and Knox Energy properties in this evaluation. CNX provided all production data as daily or monthly wellhead data in an Aries^TM database or electronic tables. This data was used to predict future performance and the appropriate shrink factors were applied to the forecast volumes to calculate remaining reserves. CNX provided a list of wells that were currently drilled but not on line as of March 31, 2005. Reserves for these wells were based on analog wells and typical production curves by area and formation. Triana Energy provided a map in the Triana JV area and CNX provided a map in the Knox Energy project detailing the locations and target formations for the undeveloped reserves. Performance data from the offset wells were used as analogs to predict the reserves associated with these locations. Future production was scheduled using typical production curves by area and formation.

Reserve estimates are strictly technical judgments. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretations. The reserve estimates presented in this report are believed reasonable; however, they are estimates only and should be accepted with the understanding that reservoir performance subsequent to the date of the estimate may justify their revision.

RESERVE CATEGORIES

Reserves were assigned to the proved developed producing (PDP), proved developed non-producing (PDNP), and proved undeveloped (PUD) reserve categories. Oil and gas reserves by definition fall into one of the following categories: proved, probable, and possible. The proved category is further divided into: developed and undeveloped. The developed reserve category is even further divided into the appropriate reserve status subcategories: producing and non-producing. Non-producing reserves include shut-in and behind-pipe reserves. The proved reserves evaluated in this report conform to the Securities and Exchange Commission Regulation S-X, Rule 4-10 (a). These reserve definitions are presented in the Reserve Definitions section of this report.

In the Virginia CBM project only frac wells CNX plans to drill in the next four years were included in the proved undeveloped reserve category. CNX has an active exploration and development program to develop their interests in certain tracts not classified as proved at this time. Future drilling may result in the reclassification of significant volumes to the proved reserve category.

The reserves and income attributable to the various reserve categories included in this report have not been adjusted to reflect the varying degrees of risk associated with them.

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ECONOMIC TERMS

Net revenue (sales) is defined as the total proceeds from the sale of oil, condensate, natural gas liquids (NGL), and natural gas before any deductions. Future net income (cashflow) is future net revenue less net lease operating, transportation, processing, and marketing expenses, and state severance or production taxes. General and administrative (G&A) expenses are deducted from future net income (cashflow) for all wells. These G&A expenses are charged to each particular well or unit on a monthly basis. Future plugging, abandonment, and salvage costs are included at the economic life of each well or unit. No provisions for State or Federal income taxes are made in this evaluation. The present worth (discounted cashflow) at various discount rates is calculated on a monthly basis.

PRICING AND ESCALATION PARAMETERS

All product prices, costs, and escalation parameters used in this report were supplied by CNX prior to preparation of this report and were accepted as presented. All pricing and costs were held constant for the life of the projects (no escalation). All economics were run to economic life or 65 years which ever occurs first. The following pricing and escalation parameters were used:

Gas–A

gas price of $7.170 per MMBtu was used in this evaluation. This price is the March 31, 2005 Henry Hub spot gas price. The gas price was adjusted for the local price differential and quality by project. Gas contracts in place in Virginia CBM project were honored as listed below in Table 2. Tables 3, 4, 5 and 6 detail the price adjustments by project. The gas prices were held constant for the life of the projects. Gas prices were not escalated.

Beginning in June, 2006 CNX will be able to move gas in two directions from the Virginia CBM project. Prior to June, 2006 production volumes in the project are curtailed during the summer curtailment period. Table 3 outlines the curtailments and basis and fees associated with the three tier gas sales.

Oil–	The oil price used for the Knox Energy Project was $49.25/Bbl. This price was adjusted a negative $2.50/Bbl for local price differential and quality for a net gas price of $46.75/Bbl. This price is the March 31, 2005 realized price for the project.

Details of the costs and economic parameters used in this report for each project area are contained in Tables 3, 4, 5, and 6. Operating costs used in this report were based on the direct costs reported by CNX for the prior 12-month period of April, 2004 through March, 2005. Currently mine operations in the Virginia CBM project pays for all capital costs associated with the short-hole horizontals, gob wells, and sealed gob wells in the active mining areas. Only the portion of the general and administrative (G&A) directly charged to leases are included in the operating costs. Development costs are based on the authorizations for expenditures for the proposed projects or similar projects in the area. Abandonment capital is included in the project at the end of the life of the wells. The total abandonment capital included in the CNX proved values is $38.3MM. The resulting net total capital excluding abandonment required to fully develop the CNX proved reserves is $319.7MM.

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TABLE 2

CONSOL ENERGY INC.

GAS PRICE CONTRACTS

MARCH 31, 2005 EVALUATION


Time Frame	Total Contract Volumes (MMBtu/Day)	Contract Price ($/MMBtu)
4/2005 through 10/2005	106,000	4.692
11/2005 & 12/2005	91,000	4.640
1/2006 through 12/2006	15,000	4.805

TABLE 3

VIRGINIA CBM MINE PROJECT

ECONOMIC DATA


Economic Parameter		Value
Tier 1 Gas Production
Gas Price Basis Adjustment, $/MMBtu		0.250
Volume, Mscf/D		Up to 100,000
Transportation Fee, $/Mscf		0.085
Tier 2 Gas Production
Gas Price Basis Adjustment, $/MMBtu		0.530
Volume, Mscf/D		100,000 – 140,000
Transportation Fee, $/Mscf		0.124
Tier 3 Gas Production
Gas Price Basis Adjustment, $/MMBtu		0.150
Volume, Mscf/D		Volumes above 140,000
Transportation Fee, $/Mscf		0.014
Summer Curtailment
August – October 2005, %		8.300
April – May 2006, %		24.300
BTU Adjustment
Frac Wells		1.007
All Other Production		0.980
Shrink Factor		1.000
Fixed Per Well Operating Cost, $/Well/Month		241.000
Variable Operating Cost, $/Mscf		0.380
Severance Tax, %		3.000
Ad Valorem Tax, %		1.000
Fixed Field Operating Cost, M$/Month
Through Active Mining		1,018.868
End of Active Mining – 2035		696.839
Remainder – 2045 (End of project life operations)		509.434

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Economic Parameter		Value
Direct Field Administrative Cost, M$/Month
Through Active Mining		471.322
End of Active Mining – 2035		353.491
Remainder – 2045 (End of project life operations)		235.661
Firm Transportation Charge
TCO 2005 – 2015, M$/M*
TCO High – 2005		355.160
TCO Low – 2015		49.800
Jewell Ridge 6/2006 – 5/2021, M$/M		653.961
Patriot 6/2006 – 5/2014, M$/M		316.322
Capital Costs
Frac Well, M$/Well		340.000
Nitrogen Regeneration System, M$		1,000.000
Generator Station, M$		3,801.000
Well Abandonment, M$		12.250
* Actual charge based on quantity purchased.

TABLE 4

TRIANA JV PROJECT

ECONOMIC DATA


Economic Parameter		Value
Gas Basis Adjustment, $/MMBtu		0.250
BTU Adjustment		1.008
Shrink Factor		1.000
Transportation Tariff, $/Mscf (Net Gas)		0.380
Fixed Per Well Operating Cost, $/Well/Month		164.000
Severance Tax, %		3.000
Ad Valorem Tax, %		0.750
Gathering Capital for Non-Producing Reserves, M$/Well		40.000
Abandonment Capital		12.250

TABLE 5

KNOX ENERGY PROJECT

ECONOMIC DATA


Economic Parameter		Value
Gas Basis Adjustment, $/MMBtu		0.045
BTU Adjustment		1.172
Shrink Factor		0.970
Variable Operating Cost, $/Mscf		0.800
Fixed Per Well Operating Cost, $/Well/Month		150.000
Severance Tax, %		3.000
Ad Valorem Tax, %		2.000
Net Completion Capital for Non-Producing Reserves, M$/Well		0.000
Net Abandonment Capital, M$/Well		12.250

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TABLE 6

NORTHERN APPALACHIAN COALBED METHANE PROJECT

ECONOMIC DATA


Economic Parameter		Value
Gas Basis Adjustment, $/MMBtu		0.290
Severance Tax, %
Pennsylvania		0.000
West Virginia		5.000
Ad Valorem Tax, %
Pennsylvania		0.000
West Virginia		6.480
Horizontal CBM Well Program
BTU Adjustment		1.000
Shrink Factor		0.850
Variable Operating Cost, $/Mscf		0.0137
Fixed Operating Cost, $/Well/Month
First 12 Months		1,200.000
12 – 24 Months		1,100.000
Remainder of Life		1,000.000
Water Disposal Expense, $/Bbl		1.500
Horizontal Well Capital, M$/Well		824.000
5 MMscf/Day Facility Capital and Expense
Field Compression and Gathering Expense, $/Month		8,957.250
Central Facility and Treating Expense, $/Month		3,410.000
Field Compression and Gathering Capital, M$		36,812.500
Central Facility and Treating Capital, M$		150.000
Abandonment Capital, M$/Well		12.250
Gob CBM Program
Fixed Expense Per Compressor, $/Month		3,624.000
Variable Expense, $/Mscf		1.800
Shrink Factor, %
Blacksville 1		0.570
Blacksville 10		0.740
Blacksville 11		0.820
Blacksville 11A		0.830
Blacksville 2		0.870
Blacksville 3		0.670
Blacksville 5		0.990
Blacksville 8		0.800
Blacksville 9		0.870
Loveridge 1		0.680
Loveridge 2		0.590
Loveridge 3		0.750
Loveridge 4		0.650
Loveridge 6		0.800
Abandonment Capital, M$/Site		12.250

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OWNERSHIP

All leasehold interests were supplied by CNX and were accepted as presented. No attempt was made by the undersigned to verify the title or ownership of the interests evaluated.

GENERAL

All data used in this study were obtained from CNX, the operator, public industry information sources, or the non-confidential files of DCS. A field inspection of the properties was not made in connection with the preparation of this report.

The potential environmental liabilities attendant to ownership and/or operation of the properties have not been addressed in this report. Abandonment and clean-up costs and possible salvage value of the equipment were considered in this report.

In evaluating the information at our disposal related to this report, we have excluded from our consideration all matters which require a legal or accounting interpretation or any interpretation other than those of an engineering or geological nature. In assessing the conclusions expressed in this report pertaining to all aspects of oil and gas evaluations, especially pertaining to reserve evaluations, there are uncertainties inherent in the interpretation of engineering data, and such conclusions represent only informed professional judgments.

Data and worksheets used in the preparation of this evaluation will be maintained in our files in Pittsburgh and will be available for inspection by anyone having proper authorization by CNX.

This report was prepared solely for the use of the party to whom it is addressed and any disclosure made by said party of this report and/or the contents thereof shall be solely responsibility of said party, and shall in no way constitute any representation of any kind whatsoever of the undersigned with respect to the matters being addressed.

Should you need further assistance in this matter, please contact one of the following DCS employees who can answer your questions or direct you to the appropriate team member.


		S. Dana Weida		Principal Consultant
		Denise L. Delozier		Senior Petroleum Engineer

We appreciate the opportunity to serve you and are available should you need further assistance in this matter.

Sincerely,


/S/ DENISE L. DELOZIER				/S/ S. DANA WEIDA
Denise L. Delozier Senior Petroleum Engineer				S. Dana Weida Principal Consultant

/S/ JOSEPH H. FRANTZ, JR.
Joseph H. Frantz, Jr. Consulting Services Operations Manager U.S. Land East

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Reserve Definitions

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SECURITIES AND EXCHANGE COMMISSION

REGULATION S-X, RULE 4-10 (A)

RESERVES DEFINITIONS

Oil And Gas Producing Activities

Such activities include (A) the search for crude oil, including condensate and natural gas liquids, or natural gas (“oil and gas”) in their natural states and original locations; (B) the acquisition of property rights or properties for the purpose of further exploration and/or for the purpose of removing the oil or gas from existing reservoirs on those properties; and (C) the construction, drilling and production activities necessary to retrieve oil and gas from its natural reservoirs, and the acquisition, construction, installation, and maintenance of field gathering and storage systems – including lifting the oil and gas to the surface and gathering, treating, field processing (as in the case of processing gas to extract liquid hydrocarbons) and field storage. For purposes of this section, the oil and gas production function shall normally be regarded as terminating at the outlet valve on the lease or field storage tank; if unusual physical or operational circumstances exist, it may be appropriate to regard the production functions as terminating at the first point at which oil, gas, or gas liquids are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal.

Oil and gas producing activities do not include (A) the transporting, refining and marketing of oil and gas; (B) activities relating to the production of natural resources other than oil and gas; (C) the production of geothermal steam or the extraction of hydrocarbons as a by-product of the production of geothermal steam or associated geothermal resources as defined in the Geothermal Steam Act of 1970; and (D) the extraction of hydrocarbons from shale, tar sands, or coal.

The SEC stated in a September 18, 1989 accounting bulletin “since coalbed methane gas can be recovered from coal in its natural state and location, it should be included in proved reserves, provided that it complies in all other respects with the SEC definitions of proved oil and gas reserves including the requirement that methane production be economical at current prices, costs (net of the tax credit) and existing operating conditions.” We have also interpreted this bulletin to include shale gas.

Proved Oil And Gas Reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids 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.

Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas

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liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Developed Oil and Gas Reserves

Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved Undeveloped Reserves

Proved undeveloped oil and gas reserves are 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual tests in the area and in the same reservoir.

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CNX GAS CORPORATION

27,936,667 Shares of

Common Stock

Prospectus

, 2005

Until (25 days after the commencement of this offering), all dealers that effect transactions in our common stock, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

Part II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth the various expenses in connection with the sale and distribution of the securities being registered. All of the amounts shown are estimated except the Securities and Exchange Commission registration fee and the New York Stock Exchange listing fee.


Securities and Exchange Commission registration fee	$	53,000
National Association of Securities Dealers, Inc. filing fee		45,200
New York Stock Exchange Listing Fee		250,000
Printing and engraving expenses		15,000
Legal fees and expenses		350,000
Legal fees and expenses for selling stockholders’ counsel		50,000
Accountants’ fees and expenses		350,000
Engineering fees and expenses		50,000
Miscellaneous		7,000
Total Expenses	$	1,170,000

Item 14. Indemnification of Directors and Officers.

Our certificate of incorporation limits the liability of directors for monetary damages for breach of fiduciary duty, except to the extent such exemption from liability is not permitted under Delaware law. Additionally, the Delaware General Corporation Law (“DGCL”) and our bylaws provide for indemnification of our officers and directors for liabilities and expenses that they may incur in such capacities. Our bylaws provide that we shall indemnify our officers and directors to the fullest extent permitted by Delaware law, including some instances in which indemnification is otherwise discretionary under Delaware law. Section 145 (“Section 145”) of the DGCL provides that a Delaware corporation may indemnify any person who was, is or is threatened to be made, party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (other than an action by or in the right of such corporation), by reason of the fact that such person is or was an officer, director, employee or agent of such corporation, or is or was serving at the request of such corporation as a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorney’s fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by such person in connection with such action, suit or proceeding, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests and, with respect to any criminal action or proceeding, had no reasonable cause to believe that his conduct was illegal. A Delaware corporation may indemnify any persons who are, were or are threatened to be made, a party to any threatened, pending or completed action or suit by or in the right of the corporation by reasons of the fact that such person is or was a director, officer, employee or agent of another corporation or enterprise. The indemnity may include expenses (including attorneys’ fees) actually and reasonably incurred by such person in connection with the defense or settlement of such action or suit, provided such person acted in good faith and in a manner he reasonably believed to be in or not opposed to the corporation’s best interests, provided that no indemnification is permitted without judicial approval if the officer, director, employee or agent is adjudged to be liable to the corporation. Where an officer or director is successful on the merits or otherwise in the defense of any action referred to above, the corporation must indemnify him against the expenses which such officer or director has actually and reasonably incurred. Our bylaws also provides that CNX Gas must pay expenses incurred in defending any such proceeding in advance of its final disposition upon delivery of an undertaking, by or on behalf of an indemnified person, to repay all amounts so advanced if it should be determined ultimately that such person is not entitled to be indemnified under this section or otherwise. The indemnification rights set forth above shall not be exclusive of any other right which an indemnified person may have or hereafter acquire under any statute, provision of our amended and restated certificate of incorporation, our bylaws, agreement, vote of stockholders or disinterested directors or otherwise. Reference is made to our certificate of incorporation and bylaws filed as Exhibits 3.1 and 3.2 respectively, hereto.

Section 145 further authorizes a corporation to purchase and maintain insurance on behalf of any person who is or was a director, officer, employee or agent of the corporation, or is or was serving at the request of the corporation as a director, officer, employee or agent of another corporation or enterprise, against any liability asserted against him and incurred by him in any such capacity, or arising out of his status as such, whether or not the corporation would otherwise have the power to indemnify him under Section 145. We have an insurance policy which insures the directors and officers of CNX Gas against certain liabilities which might be incurred in connection with the performance of their duties. The insurer is permitted to pay amounts on our behalf to the directors and officers for which we have granted indemnification.

Item 15. 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 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 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, 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 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 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 and September 2005, CNX Gas issued options to purchase CNX Gas common stock to its employees and executive officers

at an exercise price of $16.00 per share and restricted stock units to its non-employee and non-CONSOL Energy employee directors. A total of 358,370 options to purchase CNX Gas common stock were granted to CNX Gas employees, other than its 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.

CNX Gas intends to comply with all applicable state securities laws and regulations relating to the private placement.

Item 16. Exhibits and Financial Statement Schedules.

(a)

The following exhibits are filed as part of this registration statement:

EXHIBITS


Exhibit Number		Description

3.1		Amended and Restated Certificate of Incorporation of CNX Gas Corporation*

3.2		Amended and Restated Bylaws of CNX Gas Corporation*

4.1		Registration Rights Agreement dated August 8, 2005 by and among CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.*

4.2		Form of stock certificate*

5.1		Opinion of Buchanan Ingersoll PC*

10.1		Summary of Employment Terms for Nicholas J. DeIuliis(1)

10.2		Offer letter for Ronald Smith(1)

10.3		Offer letter for Gary J. Bench*

10.4		Offer letter for Stephen W. Johnson*

10.5		CNX Gas Corporation Equity Incentive Plan and form of award agreements thereunder*

10.6.1		Form of Change in Control Agreement for executive officers DeIuliis and Bench*

10.6.2		Form of Change in Control Agreement for executive officers Smith and Johnson*

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(2)

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)(2)

10.9		Tax Sharing Agreement dated August 1, 2005 between CONSOL Energy Inc. and CNX Gas Corporation(2)

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(2)

10.11		Intercompany Revolving Credit Agreement between CONSOL Energy Inc. and CNX Gas Corporation(2)


Exhibit Number		Description

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(2)

10.13		Summary sheet regarding director compensation*

10.14		Purchase/Placement Agreement dated August 1, 2005 by and between CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.*

10.15		Credit Agreement dated October 7, 2005 between CNX Gas Corporation, certain of its subsidiaries, and the Lender parties thereto.(3)

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(4)

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(5)

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(6)

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(7)

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(2)

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*

10.22		Precedent Agreement dated July 29, 2005 by and between East Tennessee Natural Gas, LLC and CNX Gas Company, LLC.

21		List of Subsidiaries*

23.1		Consent of PricewaterhouseCoopers LLP

23.2		Consent of Schlumberger Data and Consulting Services*

23.3		Consent of Ralph E. Davis Associates, Inc.*

23.4		Consent of Buchanan Ingersoll PC (included in Exhibit 5.1)*

24.1		Power of Attorney (included on the signature page hereto)

*	Previously filed.

(1)	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)

(2)	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)

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

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

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

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

(7)	Incorporated by reference from Exhibit 4.2 to Form 10-Q filed by CONSOL Energy Inc. on August 3, 2005

Item 17. Undertakings.

The undersigned registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933, as amended;

(ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and

(iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement;

(2) That, for the purpose of determining any liability under the Securities Act of 1933, as amended, each such post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the foregoing provisions, or otherwise, the Registrant has been advised that in the opinion of the Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, as amended, the Registrant has duly caused this Amendment No. 4 to this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in Pittsburgh, Pennsylvania on December 16, 2005.


CNX GAS CORPORATION

By:		/S/ NICHOLAS J. DEIULIIS
		Nicholas J. DeIuliis Chief Executive Officer

POWER OF ATTORNEY

Pursuant to the requirements of the Securities Act of 1933, as amended, this Amendment No. 4 to this Registration Statement has been signed below by the following persons in the capacities and on the dates indicated.


Signature	Capacity	Date

/S/ NICHOLAS J. DEIULIIS Nicholas J. DeIuliis	Chief Executive Officer, President and Director (principal executive officer)	December 16, 2005

/S/ GARY J. BENCH Gary J. Bench	Chief Financial Officer (principal financial officer and principal accounting officer)	December 16, 2005

* Philip W. Baxter	Chairman of the Board of Directors	December 16, 2005

* J. Brett Harvey	Director	December 16, 2005

* James E. Altmeyer, Sr.	Director	December 16, 2005

Raj K. Gupta	Director	December 16, 2005

* John R. Pipski	Director	December 16, 2005

* William J. Lyons	Director	December 16, 2005



*		/S/ NICHOLAS J. DEIULIIS
		Attorney-In-Fact