10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)


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

For the fiscal year ended December 31, 2006;


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

For the transition period from to

Commission file number: 001-32723

CNX GAS CORPORATION

(Exact name of registrant as specified in its charter)


Delaware		20-3170639
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		Identification No.)

4000 Brownsville Road
South Park, PA 15129-9545
(412) 854-6719
(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Securities registered pursuant to Section 12(b) of the Act:


Title Of Each Class		Name of Each Exchange On Which Registered

Common Stock ($.01 par value)		New York Stock Exchange

No securities are registered pursuant to Section 12(g) of the Act.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

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

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

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

The aggregate market value of voting stock held by nonaffiliates of the registrant as of June 30, 2006, based on the closing price of the common stock on the New York Stock Exchange on such date ($30.00 per share), was $834,112,650. For purposes of determining this amount, affiliates include directors and executive officers, who, as of June 30, 2006, in the aggregate held 132,912 shares, and CONSOL Energy Inc., which held 122,896,667 shares.

The number of shares outstanding of the registrant’s common stock as of January 31, 2007 is 150,864,825 shares.

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of CNX Gas Corporation’s Proxy Statement for the Annual Meeting of Stockholders to be held on April 23, 2007, are incorporated by reference in Items 10, 11, 12, 13 and 14 of Part III

FORWARD-LOOKING STATEMENTS

We are including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf, of us. With the exception of historical matters, the matters discussed in this Annual Report on Form 10-K are forward-looking statements (as defined in Section 21E of the Exchange Act) that involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects and our future production, revenues, income and capital spending. When we use the words “believe,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project,” or their negatives, or other similar expressions, the statements which include those words are usually forward-looking statements. When we describe strategy that involves risks or uncertainties, we are making forward-looking statements. The forward-looking statements in this Annual Report on Form 10-K speak only as of the date of this Annual Report on Form 10-K; we disclaim any obligation to update these statements unless required by securities law, and we caution you not to rely on them unduly. We have based these forward-looking statements on our current expectations and assumptions about future events. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks, contingencies and uncertainties relate to, among other matters, the following:

	•		our business strategy;

	•		our financial position, cash flow and liquidity;

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

	•		uncertainties in estimating our gas reserves and replacing our gas reserves;

	•		uncertainties in exploring for and producing gas;

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

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

	•		the availability of personnel and equipment, including our inability to retain and attract key personnel;

	•		increased costs;

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

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

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

	•		our relationships and arrangements with CONSOL Energy; and

	•		other factors discussed under “Risk Factors.”

PART I

ITEM 1. BUSINESS

Except as otherwise noted or unless the context otherwise requires, (i) the information in this Annual Report on Form 10-K gives effect to the contribution to CNX Gas of the CONSOL Energy gas business effective as of August 8, 2005, (ii) CNX Gas refers, with respect to any date prior to the effective date of that contribution, to the CONSOL Energy gas business and, with respect to any date on or subsequent to the effective date of the contribution, to CNX Gas and our subsidiaries, (iii) “CONSOL Energy” refers to CONSOL Energy Inc. and its subsidiaries other than CNX Gas and the companies which conducted CONSOL Energy’s gas business, and (iv) reserve and operating data are as of December 31, 2006 unless otherwise indicated. The estimates of our proved reserves as of December 31, 2006 and 2005 included in this Annual Report are based on reserve reports prepared by Schlumberger Data and Consulting Services. The estimates of our proved reserves as of December 31, 2004 included in this Annual Report are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. Similarly, the estimates of our proved reserves as of December 31, 2004 and 2003 (set forth in Item 6, “Selected Financial Data – Other Financial Data”) are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. Unless otherwise noted, we discuss production, per unit revenue and per unit costs net of any royalty owners’ interest. With respect to production and reserves, we use the word “net” to indicate when a number does not include the royalty owners’ interest. With respect to acres, we use the word “net” to describe our aggregate fractional interest in property that we control by deed or lease. With the exception of earnings per share data, we discuss dollars in thousands throughout this Form 10-K. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, for the twelve months ended December 31, 2006, 2005 and 2004 is included in Note 16 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

General

We are engaged in the exploration, development, production and gathering of natural gas primarily in the Appalachian Basin, and we are expanding our operations into the Illinois Basin. In particular, we are a leading developer of coalbed methane (CBM). CONSOL Energy Inc. (CONSOL Energy) owns 81.5% of our outstanding common stock. In August 2005, we acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other western basins. As of December 31, 2006, we had 1.265 Tcfe of net proved reserves, including our portion of equity affiliates, with a PV-10 value of $1,499,664 and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of $934,891. Our proved reserves are approximately 99% CBM and 48% proved developed. We are one of the largest gas producers in the Appalachian Basin with net sales of 56.1 Bcf for the twelve months ended December 31, 2006. Our proved reserves are long-lived with a reserve life index of 22.5 years.

We began extracting CBM in the early 1980s in order to reduce the gas content in the coal being mined by CONSOL Energy. We developed techniques to extract CBM from coal seams prior to mining in order to enhance the safety and efficiency of CONSOL Energy’s mining operations. As a result of our more than 20 years of experience with CBM extraction, we believe our management has developed industry-leading expertise in this type of gas production.

History of CNX Gas

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

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

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

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

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

Our Relationship with CONSOL Energy

Prior to August 2005, we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy, a public company traded on the NYSE under the symbol CNX. Those companies include: CNX Gas Company, LLC; Cardinal States Gathering Company (“CSGC”); a 50.0% interest in Coalfield Pipeline Company; a 50.0% interest in Knox Energy LLC; a joint venture with Kelly Oil and certain other entities; and a 50.0% interest in Buchanan Generation, LLC. These are the companies primarily responsible for the exploration, production, gathering and sale of our gas, with the exception of Buchanan Generation, LLC. Buchanan Generation, LLC uses our gas to generate electricity from a generating facility located near our Virginia gas field. CONSOL Energy owns 81.5% of the outstanding common stock of CNX Gas.

The success of our operations substantially depends upon rights we received from CONSOL Energy. As a part of our separation from CONSOL Energy, CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of CONSOL Energy’s ownership or rights to CBM, natural gas, oil, and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with its coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements under which CONSOL Energy will provide us certain corporate staff services and coordinate our tax filings.

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

Coordination with Mining Activities

Approximately 13.5% of our current gas production is produced in connection with coal extraction by CONSOL Energy (not including another approximately 16.0% of our production that is associated with previously mined areas). It is essential that gas liberated by the mining process be removed from the mine in order to maintain a safe working environment in the mine. As a result, a portion of our gas extraction activity is determined based upon the needs of the related mining activity.

Through close cooperation and coordination between CNX Gas and CONSOL Energy, we prepare an annual drilling program that meets the needs of both companies. The master cooperation and safety agreement provides that each year, in consultation with CONSOL Energy, CNX Gas will outline its drilling plans to show: (i) the general area of drilling and the number of wells proposed to be drilled in the following calendar year, and (ii) the approximate location of all production, treatment and gathering related systems proposed to be installed by CNX Gas.

Gas Operations

We primarily produce CBM, which is gas that resides in coal seams. In the eastern United States, conventional natural gas fields typically are located in various types of sedimentary formations at depths ranging from 2,000 to 15,000 feet. Exploration companies often put their capital at risk by searching for gas in commercially exploitable quantities at these depths. By contrast, gas in the coal seams that we drill or anticipate drilling is typically in formations less than 2,500 feet deep which are usually better defined than deeper formations. We believe that this contributes to lower exploration costs than those incurred by producers that operate in deeper, less defined formations.

Areas of Operation

In the Appalachian Basin we operate principally in Central Appalachia and Northern Appalachia, which represent our two reportable segments. We also operate in the Illinois Basin. The four areas we see playing prominent roles in our portfolio in the near future are as follows:

•		first, in Central Appalachia, Virginia Operations CBM, our traditional area of operation, where we have typically produced CBM from vertical wells which we drill ahead of mining and gob gas from wells paid for by CONSOL Energy to de-gas their coal mines;

•		second, in Northern Appalachia, the Mountaineer CBM play in northwestern West Virginia and southwestern Pennsylvania where our first major drilling program using vertical to horizontal well methodology has shown good results;

•		third, in Northern Appalachia, the Nittany CBM play in central Pennsylvania, where we have substantial holdings and have completed initial testing activities; and

•		last, in the Illinois Basin, Cardinal, the New Albany Shale play in western Kentucky and southern Illinois, which has compelling economic potential similar to Nittany and Mountaineer.

Central Appalachia

Virginia Operations CBM

We have the right to extract CBM in this region from approximately 290,000 net CBM acres, which cover a portion of the over 424 million tons of recoverable coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas per ton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

We coordinate some of our CBM extraction with the subsurface coal mining of CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam ahead of the planned mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” Presently, frac wells account for approximately 72.0% 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 that are drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is 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 coal seams that cannot be mined, collapses into the void. These seams become extensively fractured and release substantial volumes of gas as they collapse. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. Approximately 26.0% of our gas production comes in the form of gob gas (11.5% active gob and 14.5% sealed gob). CONSOL Energy pays for the drilling of our gob wells in most instances.

Recently, we began drilling long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorption of CBM from the coal seam. As of December 31, 2006, we have drilled 15 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. The results from these wells are encouraging and suggest that a more efficient recovery of gas in place is possible ahead of mining operations. The production rates from frac wells have not been adversely impacted by the introduction of nearby horizontal wellbores in the coal seam. In fact, we believe production at offsetting frac wells has actually increased due to the further reductions in pressure within the coal seam caused by the horizontal wells. We intend to increase our use of the horizontal wells drilled within an active mine in our future development plans. In-mine horizontal wells account for approximately 2.0% of current daily production.

Tennessee

We are exploring for natural gas in various formations at depths up to 7,000 feet with a joint venture partner and through a farm-out arrangement on approximately 206,000 gross leasehold acres in this region. In 2006, we extended the farm-out arrangement through the end of 2007, with a small portion of the acreage covered through 2011. At December 31, 2006, we had 2.2 Bcfe of proved reserves in this area. As of December 31, 2006, we have 37.5 net wells that we are operating, while we also participate in another 5.9 net wells operated by a third party. In total, we have an inventory of approximately 2,900 drilling locations on this acreage, none of which are proved undeveloped locations. We also have the right to test and produce from the Chattanooga Shale formation in this area.

We also control other property in East Kentucky and Tennessee that represents approximately 94,600 CBM acres, and 62,500 oil and gas acres.

Northern Appalachia

Mountaineer CBM

We have the right to extract CBM in this region from approximately 523,000 net CBM acres, which contain most of the over 2.7 billion tons of recoverable coal reserves owned or controlled by CONSOL Energy in Northern Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We produce gas primarily from the Pittsburgh #8 coal seam. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to over 7,000 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

Due to the significant geological differences between the Pittsburgh #8 seam in Mountaineer and the Pocahontas #3 seam in Virginia, we have found that alternative extraction techniques are more effective than vertical frac wells in this area. Instead of using frac wells, we utilize well designs that rely on the application of vertical-to-horizontal drilling techniques. This well design includes a vertical wellbore that is intersected by a second well that has up to three horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending up to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of coal surface area allowing for the migration of water and CBM from the coal seam. This design creates up to 15,000 feet of total productive wellbore. The wells are spaced in up to one square mile sections. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region associated with CONSOL Energy’s mines.

In 2006, we drilled, completed and connected to the sales line 10 vertical-to-horizontal CBM wells in Mountaineer. We expect to achieve peak production rates of nearly 4 Mcf per 100 feet of lateral exposure in the Blacksville area of this play. As of December 31, 2006, wells that have been de-watered are meeting this expectation.

Nittany CBM

We have the right to extract CBM in this region of Pennsylvania from approximately 248,000 net CBM acres. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We expect to produce CBM in Nittany using both vertical-to-horizontal wells and traditional vertical frac wells. In 2006 we drilled two vertical test wells. As of December 31, 2006, both had been fractured. During the first quarter of 2007, we plan to begin controlled production, seam by seam, in these wells in order to better estimate the gas content and productive capability of each individual seam.

Illinois

Cardinal

As of December 31, 2006, we controlled approximately 70,000 acres of oil and gas rights, which include the rights to gas in the New Albany Shale in western Kentucky and southern Illinois. The New Albany Shale is a formation containing gaseous hydrocarbons and our acreage position has an average thickness of 300 feet at an average depth of 3,880 feet. As of December 31, 2006, we have identified test well locations and we have spudded the first well. We are using a standard drilling rig to drill approximately 4,000 vertical feet. When drilling is complete, we will re-enter the hole with a device that takes sidewall core samples into the shale formation within the expected 300-foot pay zone. These samples may take several months to analyze.

Other

In addition to the Cardinal play in the Illinois Basin, we control 33,000 additional oil & gas acres. We also control 92,000 net CBM acres which contain most of the over 700 million tons of recoverable coal reserves owned or controlled by CONSOL Energy in Illinois.

Other Conventional Oil & Gas and CBM

We have acquired all of CONSOL Energy’s rights associated with CBM from over 270 million tons of recoverable coal reserves owned or controlled by CONSOL Energy throughout other regions of the United States. We do not currently have any producing 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.

Other Assets

In addition to our production assets, CNX Gas typically constructs, owns and operates its gathering and processing mid-stream infrastructure.

Each gathering system begins at the individual wellhead, delivering gas into a major trunkline that connects to the interstate pipeline system. Among our most significant gathering systems is our Cardinal States Gathering System in our Virginia Operations. There, gas from our wells is gathered from 1,030 miles of various diameter pipe and collected into our two main trunklines—Cardinal States No. 1 and Cardinal States No. 2. Cardinal States No. 1 is a 50-mile, 16-inch gathering system capable of transporting 100,000 Mcf of gas per day. Cardinal States No. 2 is a 30-mile, 20-inch gathering line currently capable of transporting 150,000 Mcf of gas per day. Our Cardinal States Gathering System connects to a Columbia Gas Transmission interstate pipeline and to the Jewell Ridge Lateral, which delivers into an East Tennessee Natural Gas (“ETNG”) interstate pipeline. We have entered into a 15- year firm transportation agreement with ETNG for 197,500 Mcf of capacity per day at pre-determined fixed rates. The aggregate capacity that we control is more than the current daily production from our Virginia operations, allowing us to expand our production in this area while realizing economies of scale. We also own and operate gathering systems in our other production regions.

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

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

Summary of Properties as of December 31, 2006


	Central			Northern			Illinois
	Appalachia			Appalachia			Basin		Other			Total
Estimated Net Proved Reserves (Bcfe)		1,220.8			32.6			—		12.1			1,265.5
Percent Developed ⁽¹⁾		47.3	%		66.9	%		—		100	%		48.2	%
Net Producing Wells		2,315.4			156.0			—		164.25			2,635.65
No. of Potential Drill Sites Available		6,898			1,876			765		—			9,539


Net Proved Developed CBM Acres		134,320			45,763			—		—			180,083
Net Proved Undeveloped CBM Acres		31,300			10,880			—		—			42,180
Net Unproved CBM Acres		341,880			806,357			92,000		—			1,240,237

Total Net CBM Acres		507,500			863,000			92,000		—			1,462,500

Gross Proved Developed Oil & Gas Acres		8,660			—			—		31,640	⁽³⁾		40,300
Gross Proved Undeveloped Oil & Gas Acres		—			—			—		—			—
Gross Unproved Oil & Gas Acres		414,340			178,000			103,000		198,360			893,700

Total Gross Oil & Gas Acres		423,000			178,000			103,000		230,000			934,000


(1)		We estimate the cost to fully develop our proved undeveloped reserves excluding abandonment is $490,600 (non-discounted and in 2006 dollars).

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

(3)		Assumes 40 acres per gross well on leased out or participating interest wells.

Our inventory of drilling sites associated with the oil and gas estate was determined by dividing our acreage in evaluated areas by the well spacing generally used in that area. In Tennessee, wells are commonly drilled on 40-acre units and in Central Appalachia, wells are drilled on an average of 110-acre spacing. The inventory of CBM locations was determined in a detailed evaluation of our Northern Appalachia and Central Appalachia reserves by Schlumberger Data & Consulting Services. The total CBM drilling site inventory reflects the sum of 80-acre and 60-acre vertical development well locations, 40-acre infill well locations and 640-acre vertical-to-horizontal well locations identified in the study. The inventory of drilling sites excludes a number of potential locations in areas not yet evaluated and the majority of potential 30-acre infill sites in Virginia CBM operations.

We control all of the properties reflected in the table above by deed or by lease, except to the extent burdened by the production joint ventures described in the table below. The aggregate production from these joint ventures represents less than 1% of total company production for 2006.

Summary of Principal Production Partners and Joint Venture Interests as of December 31, 2006

Production Partners

and Joint Venture

Working

Area

Type

Interests

Acreage

Interest

How Acquired

Central Appalachia

Oil & Gas

Columbia Natural Resources, LLC

132,000 Gross Oil &
Gas Acres

Received from CONSOL Energy

Central Appalachia

Oil & Gas

New River Energy, LLC ⁽¹⁾

206,000 Gross Oil &
Gas Acres

Acquired through lease jointly with New River Energy, LLC

Northern Appalachia

Oil & Gas

Kelly Oil and Gas, Inc., Excelsior Exploration Corporation, KWR Ventures LLC and Ceja Corporation

36,000 Gross Oil &
Gas Acres

Acquired through a working interest

Central Appalachia

CBM

Appalachian Energy, Inc.

4,200 Gross CBM
Acres

Contribution of acres by each party


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

Drilling

During the twelve months ended December 31, 2006, 2005 and 2004, we drilled 314, 225 and 228 net development wells, respectively, all of which were productive. These well counts include gob wells and wells drilled by CNX Gas. Wells drilled by other operators that we participate in are excluded. As of December 31, 2006, we have not had any dry development wells, and 41 wells are still in process. The following table illustrates the wells referenced above by geographic region:

Development Wells (Net)


	Twelve Months Ended December 31,
	2006		2005		2004
Central Appalachia		290		206		222
Northern Appalachia		24		19		6

Total		314		225		228

During the twelve months ended December 31, 2006, 2005 and 2004, we drilled in the aggregate 4, 15 and 12 net exploratory wells, respectively. The following table illustrates the exploratory wells by geographic region:

Exploratory Wells (Net)


	Twelve Months Ended December 31,
	2006						2005						2004
	Producing		Dry		Still Eval.		Producing		Dry		Still Eval.		Producing		Dry		Still Eval.
Central Appalachia		2		0		0		2		0		0		5		0		0
Northern Appalachia		0		0		2		13		0		0		7		0		0

Total		2		0		2		15		0		0		12		0		0

Summary of Other Operating Data

Production

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

Twelve Months Ended

December 31,

2006

2005

2004

Total Produced (Mmcf)

56,135

48,390

48,556

Average Sales Prices and Lifting Costs

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


	Twelve Months Ended
	December 31,
	2006		2005		2004
Average Gas Sales Price Including Effects of Financial Settlements (per Mcf)	$	7.04	$	5.90	$	4.90
Average Lifting Cost (per Mcf)	$	0.56	$	0.57	$	0.50

Productive Wells and Acreage

The following table sets forth, at December 31, 2006, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:


	Gross		Net ⁽¹⁾
Producing Wells		3,232		2,636
Proved Developed Acreage		220,383		190,134
Proved Undeveloped Acreage		42,900		42,180
Unproven Acreage		2,197,397		1,776,786

Total Acreage		2,460,680		2,009,100

Most of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied.

(1)

Net acres do not include acreage attributable to the working interests of our principal joint venture partners and the portions of certain proved developed acreage attributable to property we have leased to third-party producers. Additional adjustments (either increases or decreases) may be required as we further develop title to and further confirm our rights with respect to our various properties in anticipation of development. We believe that our assumptions and methodology in this regard are reasonable.

Sales

CNX Gas enters into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance, we have not failed to deliver quantities required under contract. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions. These financial, as well as physical hedges, represented approximately 27% of our produced gas sales volumes for the twelve months ended December 31, 2006 at an average price of $7.42 per Mcf. As of December 31, 2006, we expect these transactions will cover approximately 20% of our estimated 2007 production.

CNX Gas has purchased firm transportation capacity on the Columbia pipeline to ensure gas production flows to market. As mentioned above in the section entitled Other Assets, as of October 2006, pursuant to our agreement with ETNG, we have a contract for firm transportation of 197,500 Mcf per day on the Jewell Ridge Lateral for the next 15 years, and 40,000 Mcf per day on ETNG’s Patriot mainline. As of December 31, 2006, CNX Gas has secured firm transportation capacity to cover more than its 2007 hedged production. CNX Gas also participates in the short-term firm transportation markets to manage flows as market conditions dictate. We expect to be able to flow all of our production in 2007 without curtailment, other than curtailments resulting from maintenance or other major events relating to our gathering system, laterals or the interstate gas pipelines.

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 Item 8 of Part II of this Annual Report.

Reserves

The following table shows our estimated proved developed and proved undeveloped reserves. Reserve information is net of royalty interest. Proved developed and proved undeveloped reserves are reserves that could be commercially recovered under current economic conditions, operating methods and government regulations. Proved developed and proved undeveloped reserves are defined by the SEC Rule 4.10(a) of Regulation S-X.


	Net Reserves (Mmcfe)
	As of December 31,
	2006				2005				2004
	Consolidated		Equity		Consolidated		Equity		Consolidated		Equity
	Operations		Affiliates		Operations		Affiliates		Operations		Affiliates
Estimated proved developed reserves		609,700		2,200		549,574		2,672		395,152		1,489
Estimated proved undeveloped reserves		653,593		—		578,150		—		647,251		896

Total estimated proved developed and undeveloped reserves		1,263,293		2,200		1,127,724		2,672		1,042,403		2,385

Discounted Future Net Cash Flows

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


	Discounted Future Net Cash Flows
	($ in thousands)
	As of December 31,
	2006		2005		2004
Future net cash flows	$	2,483,887	$	5,149,938	$	2,872,571
Total PV-10 measure of pre tax discounted future net cash flows (1)	$	1,499,664	$	3,051,866	$	1,655,232
Total standardized measure of after tax discounted future net cash flows	$	934,891	$	1,870,794	$	1,029,538


(1)		We calculate our PV-10 value in accordance with the following table. Management believes that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and sophisticated investors in evaluating oil and gas companies. Because many factors that are unique to each individual company impact the amount of future income taxes estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. All firm transportation costs are included in the PV-10 calculation. However, costs associated with our capital lease obligations are excluded from the PV-10 calculation. If these costs were included, the December 31, 2006 PV-10 calculation would be approximately $1,441,000. We have included a reconciliation to the most directly comparable GAAP measure—after-tax discounted future net cash flows.

Reconciliation of PV-10 to Standardized Measure


	As of
	December 31,
	2006			2005			2004
Future cash inflows	$	7,105,265		$	11,675,551		$	6,337,257
Future Production Costs		(2,568,731	)		(2,852,033	)		(1,453,364	)
Future Development Costs (including abandonments)		(552,114	)		(422,315	)		(265,540	)

Future net cash flows		3,984,420			8,401,203			4,618,353
10% discount factor		(2,484,756	)		(5,349,337	)		(2,963,121	)

PV-10 (Non-GAAP measure)		1,499,664			3,051,866			1,655,232

Undiscounted Income Taxes		(1,500,533	)		(3,251,265	)		(1,745,782	)
10% discount factor		935,760			2,070,193			1,120,088

Discounted Income Taxes		(564,773	)		(1,181,072	)		(625,694	)

Standardized GAAP measure	$	934,891		$	1,870,794		$	1,029,538

Competition

Competition throughout the country is regionalized. We operate in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on operating cost and the proximity of gas fields to customers.

Employee and Labor Relations

As of December 31, 2006, CNX Gas had 192 employees. None of our employees is represented by a union. We believe our relationship with our employees is satisfactory.

Regulations

The natural gas industry is subject to regulation by federal, state and local authorities on matters such as employee health and safety, permitting and licensing requirements, air quality standards, water pollution, the treatment, storage and disposal of wastes, plant and wildlife protection, storage tanks, the reclamation of properties and plugging of wells after gas operations are completed, the discharge or release of materials into the atmosphere and the environment, and the effects of gas well operations on groundwater quality and availability. Additional regulations, including regulations applicable to mine safety, may also be applicable to gas operations producing coalbed methane in relation to active mining. The possibility exists that new legislation or regulations may be adopted which would have a significant impact on our operations or our customers’ ability to use gas and may require us or our customers to change operations significantly or incur substantial costs.

Environmental Regulation of Gas Operations

Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines and penalties. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to CNX Gas and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new environmental regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste.

It is not possible to quantify the costs of compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the twelve months ended 2006, 2005 and 2004. CNX Gas expects to incur capital expenditures of $1,490 related to water treatment costs in 2007. 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 and regulations cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for disposal.

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

	•		the Clean Air Act;

	•		the Clean Water Act;

	•		the Toxic Substances Control Act;

	•		the Endangered Species Act:

	•		the Resource Conservation and Recovery Act; and

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

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

These environmental laws require monitoring, reporting, permitting and/or approval of many aspects of gas operations. Both federal and state inspectors regularly inspect facilities during construction and during operations after construction. We have ongoing environmental management, compliance and permitting programs designed to assist in compliance with such environmental laws. We believe that we have obtained all required permits under federal and state environmental laws for our current gas operations. Further, we believe that we are in substantial compliance with such permits. However, if violations of permits, failure to obtain permits or other violations of federal or state environmental laws are discovered, we could incur significant liabilities: to correct such violations; to provide additional environmental controls; to obtain required permits; and to pay fines which may be imposed by governmental agencies. New permit requirements and other requirements imposed under federal and state environmental laws may cause us to incur significant additional costs that could adversely affect our operating results.

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

Federal Regulation of the Sale and Transportation of Gas

Various aspects of CNX Gas’ operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. While “first sales” by producers of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

Regulations and orders set forth by the Federal Energy Regulatory Commission also impact the business of CNX to a certain degree. Although the Federal Energy Regulatory Commission does not directly regulate CNX Gas’ production activities, the Federal Energy Regulatory Commission has stated that it intends for certain of its orders to foster increased competition within all phases of the natural gas industry. Additionally, the Federal Energy Regulatory Commission continues to review its transportation regulations, including whether to allocate all short-term capacity on the basis of competitive auctions and whether changes to its long-term transportation policies may also be appropriate to avoid a market bias toward short-term contracts. Additional Federal Energy Regulatory Commission orders were adopted based on this review with the goal of increasing competition for natural gas markets and transportation.

The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. 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, the disposal of fluids used in connection with operations , and gas operations producing coalbed methane in relation to active mining. CNX Gas’ operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units 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, and generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. These regulatory burdens may affect profitability, and CNX Gas is unable to predict the future cost or impact of complying with such regulations.

Ownership of Mineral Rights

The majority of our drilling operations are conducted on properties related to CONSOL Energy’s coal holdings. Our existing rights are often dependent on CONSOL Energy having obtained valid title to its properties.

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

Our natural gas properties are subject to customary royalty and other interests and burdens which we believe do not materially interfere with the use of or affect our carrying value of the properties.

The following summary sets forth an analysis of provisions of Pennsylvania, Virginia and West Virginia law relating to the ownership of CBM. These summaries do not purport to be complete and are qualified in their entirety by reference to the provisions of applicable law and rights and the laws relating to traditional natural gas resources may differ materially from the rights related to CBM. These summaries are based on current law as of the date of this Annual Report.

Pennsylvania

In Pennsylvania, CBM that remains inside the coal seam is generally the property of the owner of that coal seam where the gas is located. CBM can be sold in place or leased by the coal owner to another party such as a producer who then would have the right to extract the gas from the coal seam under the terms of the agreement with the coal owner. Once the gas migrates from the coal into other strata, the coal owner no longer has clear title to that migrated gas. As a result, in certain circumstances in Pennsylvania (e.g., in a gob or mine void), we may be required to obtain other property interests (beyond ownership or leasehold interest in the coal rights or CBM) in order to extract gas that is no longer located in the coal seam.

Virginia

The vast majority of CBM we produce as well as our proved reserves are in Virginia, 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 December 31, 2006, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia.

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

We anticipate in future years to more actively explore for and develop Northern Appalachian CBM in West Virginia. As indicated, we may need or desire to acquire additional rights from other holders of real estate interests, including acquiring rights from other real estate interest holders if the law at that time continues to lack clarity on ownership rights to CBM in West Virginia. As we explore and develop this other acreage where CONSOL Energy has coal rights and has leased/conveyed to us CONSOL Energy’s rights to CBM, we expect in accordance with our existing procedures to have a title examination performed of CONSOL Energy’s rights to CBM. If we believe we need to obtain additional rights from the holders of other real estate interests, we have developed a methodology as part of deciding the feasibility of developing a particular tract to evaluate the ability to locate and negotiate a royalty arrangement with those other holders or use force pooling under the West Virginia Act.

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. The ownership of CBM in these other states may be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.

GLOSSARY OF NATURAL GAS AND COAL TERMS

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

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

Bcf. Billion cubic feet of natural gas.

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

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

CBM. Coalbed methane.

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

Coal Seam. A single layer or stratum of coal.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Mcf. Thousand cubic feet of natural gas.

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

MMBtu. Million British thermal units.

Mmcf. Million cubic feet of natural gas.

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

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

Northern Appalachia. As used in this Annual Report, Northern Appalachia includes 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.

Pipeline imbalance (imbalance). We have an operational balancing agreement with Columbia Gas Transmission Corporation (“Columbia”). This agreement is in accordance with the Council of Petroleum Accountants Societies’ definition of producer imbalances, whereby the operator controls the physical production and delivery of gas to a transporter. Contracted quantities of gas rarely equal physical deliveries. As the operator, CNX Gas is responsible for monitoring this imbalance and making adjustments to sales volumes as circumstances warrant. The imbalance agreement is managed internally using the sales method of accounting. The sales method recognizes revenue when the gas is taken and paid for by the purchaser.

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

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

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

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

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

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

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

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

Tcfe. Trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one bbl of crude oil, condensate or natural gas liquids.

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

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

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

EXECUTIVE OFFICERS OF THE COMPANY

Incorporated by reference into this Part I is the information set forth in Part III, Item 10 under the caption “Executive Officers of CNX Gas Corporation” (included herein pursuant to Item 401(b) of Regulation S-K).

ITEM 1A. RISK FACTORS

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

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

Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. In the past we have used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. If we choose not to engage in, or reduce our use of hedging arrangements in the future, we may be more adversely affected by changes in natural gas and oil prices than our competitors who engage in hedging arrangements to a greater extent than we do.

Prices for natural gas and oil may fluctuate widely in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:

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

	•		the price of foreign imports;

	•		overall domestic and global economic conditions;

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

	•		weather conditions;

	•		technological advances affecting energy consumption;

	•		domestic and foreign governmental regulations;

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

	•		the price and availability of alternative fuels.

Many of these factors may be beyond our control. Because approximately 100% of our estimated proved reserves as of December 31, 2006 were natural gas reserves, our financial results are more sensitive to movements in natural gas prices. Earlier in this decade, natural gas prices were lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis, but may also limit our access to capital. A significant decrease in price levels for an extended period would negatively affect us in several ways including:

	•		our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production; and

	•		access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

Additionally, lower natural gas prices may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs increase, production data factors change, or our exploration results deteriorate, accounting rules may require us to write down as a non-cash charge to earnings the carrying value of our oil and natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.

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

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

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

	•		geological conditions;

	•		changes in governmental regulations and taxation;

	•		assumptions governing future prices;

	•		the amount and timing of actual production;

	•		future operating costs; and

	•		capital costs of drilling new wells.

The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the natural gas and oil industry in general. In addition, if natural gas prices decline by $0.10 per Mcf, then the pre-tax PV-10 of our proved reserves as of December 31, 2006 would decrease from $1,499,664 to $1,455,700. The standardized GAAP measure associated with this decline of $0.10 per Mcf, would be approximately $907,483.

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

Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2006, production is expected to decline even if those proved undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Our exploration and development activities may not be commercially successful.

The exploration for and production of gas involves numerous risks. The cost of drilling, completing and operating wells for CBM or other gas is often uncertain, and a number of factors can delay or prevent drilling operations or production, including:

	•		unexpected drilling conditions;

	•		title problems;

	•		pressure or irregularities in geologic formations;

	•		equipment failures or repairs;

	•		fires or other accidents;

	•		adverse weather conditions;

	•		reductions in natural gas 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.

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

We have not historically invested a significant portion of our capital budget in development projects in areas outside of Virginia CBM; however, in 2007 and beyond we plan to conduct testing and development activities in areas where we have little or no proved reserves, such as certain areas in Pennsylvania and Kentucky. These exploration, drilling and production activities will be subject to many risks, including the risk that methane gas is not present in sufficient quantities in the coalseam to be produced economically. We have invested in property, and will continue to invest in property, including undeveloped leasehold acreage, that we believe will result in projects that will add value over time. Drilling for CBM, natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs. We cannot be certain that the wells we drill in these new areas will be productive or that we will recover all or any portion of our investments.

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

We transport our gas to market by utilizing pipelines owned by others. If pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, reducing our profitability. If we cannot access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. If our sales are reduced because of transportation constraints, our revenues will be reduced, which will also increase our unit costs. If we cannot obtain transportation capacity and we do not have the ability to store gas, we may have to reduce production.

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

Due to current industry demands, well service providers and related equipment are in short supply. The demand for qualified and experienced field personnel to drill wells and conduct field operations, including geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These shortages may lead to escalating prices, the possibility of poor services, inefficient drilling operations, and personnel injuries. Such pressures will likely increase the actual cost of services, extend the time to secure such services and add costs for damages due to accidents sustained from the over use of equipment and inexperienced personnel. Higher oil and natural gas prices generally stimulate increased demand and result in increased prices for drilling equipment, crews and associated supplies, equipment and services. We believe that these shortages could continue. In addition, the costs and delivery times of equipment and supplies are substantially greater in periods of peak demand. Accordingly, we cannot assure you that we will be able to obtain necessary drilling equipment and supplies in a timely manner or on satisfactory terms, and we may experience shortages of, or material increases in the cost of, drilling equipment, crews and associated supplies, equipment and services in the future. Any such delays and price increases could adversely affect our ability to pursue our drilling program and our results of operations.

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

The gas industry is intensely competitive and we compete with companies from various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, 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.

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

From time to time we consider various acquisition opportunities. We could be subject to significant liabilities related to any completed acquisition. Generally, it is not feasible to review in detail every individual property included in an acquisition. Ordinarily, a review is focused on higher valued properties. However, even a detailed review of all properties and records may not reveal existing or potential problems in all of the properties, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. We will not always inspect every well we acquire, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is performed.

In addition, there is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Our acquisition strategy is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Our ability to pursue our acquisition strategy may be hindered if we are not able to obtain financing on terms acceptable to us or regulatory approvals.

Acquisitions often pose integration risks and difficulties. In connection with future acquisitions, the process of integrating acquired operations into our existing operations may result in unforeseen operating difficulties and may require significant management attention and financial resources that would otherwise be available for the ongoing development or expansion of existing operations. Future acquisitions could result in our incurring additional debt, contingent liabilities, expenses and diversion of resources, all of which could have a material adverse effect on our financial condition and operating results.

The coal beds from which we produce methane gas frequently contain water and the methane gas often contains impurities, both of which may hamper our ability to produce gas in commercial quantities or economically.

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. Further, a substantial amount of our gas needs to be processed in order to make it salable to our intended customers. At times, the cost of processing this gas relative to the quantity of gas from a particular well, or group of wells, may outweigh the economic benefit of selling that gas, and our profitability may decrease due to the reduced production and sale of gas.

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

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

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

We have entered into several joint venture arrangements with third parties. For example, we are involved with third parties in Knox Energy (exploration and production), Coalfield Pipeline Company (Coalfield Pipeline) (gas pipeline) and Buchanan Generation, LLC (Buchanan Generation) (peaker electrical power generation plant) and in a participation agreement with Kelly Oil & Gas, Inc. (Kelly Oil), Excelsior Exploration Corporation, KWR Ventures, LLC and Ceja Corporation (exploration and production). We may also enter into other arrangements like these in the future. 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, 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 and delays to produce gas because we have to acquire additional property rights to perfect our title to the gas estate.

Some of the gas rights we believe we control are in areas where we have not yet done any exploratory or production drilling. Most of these properties were acquired by CONSOL Energy primarily for the coal rights, and, in many cases were acquired years ago. While chain of title work for the coal estate was generally fully developed, in many cases, the gas estate title work is less robust. Our practice is to perform a thorough title examination of the gas estate before we commence drilling activities and to acquire any additional rights needed to perfect our ownership of the gas estate for development and production purposes. We may incur substantial costs to acquire these additional property rights and the acquisition of the necessary rights may not be feasible in some cases. Our inability to obtain these rights may adversely impact our ability to develop those properties. Some states permit us to produce the gas without perfected ownership under an administrative process known as “forced pooling,” which require us to give notice to all potential claimants and pay royalties into escrow until the undetermined rights are resolved. As a result, we may have to pay royalties to produce gas on acreage that we control and these costs may be material. Further, the forced pooling process is time-consuming and may delay our drilling program in the affected areas.

In addition, although CONSOL Energy has conveyed to us all of their rights to extract and produce CBM from locations where they possess rights to coal, in some cases CONSOL Energy may not possess these rights. If we are unable in such cases to obtain those rights from their owners, we will not enjoy the rights to develop the CBM with CONSOL Energy’s mining of coal, as provided in the master cooperation and safety agreement. Our failure to obtain these rights may adversely impact our ability in the future to increase production and reserves. For example, we have substantial acreage in West Virginia for which we have not reviewed the title to determine what, if any, additional rights would be needed to produce CBM from those locations or the feasibility of obtaining those rights.

In addition to acquiring these property right assets on an “as is, where is basis”, we have assumed all of the liabilities related to these assets, even if those liabilities were as a result of activities occurring prior to CONSOL Energy’s transfer of those assets to us. Our assumption of these liabilities is subject to the following allocation: we will be responsible for the first $10,000 of aggregate unknown liabilities; CONSOL Energy will be responsible for the next $40,000 of aggregate unknown liabilities; and we will be responsible for any additional unknown liabilities over $50,000. We will also be responsible for any unknown liabilities which were not asserted in writing by August 7, 2010.

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 through without jeopardizing mine-safety and a well that will ensure well bore integrity throughout its projected life.

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

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

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

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

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

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

Risks Relating to Our Relationship with CONSOL Energy

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

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

	•		the election and removal of directors;

	•		mergers or other business combinations involving us;

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

	•		amendments to our certificate of incorporation and bylaws.

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

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

Potential conflicts may arise between us and CONSOL Energy that may not be resolved in our favor.

The relationship between CONSOL Energy and us may give rise to conflicts of interest with respect to, among other things, transactions and agreements among CONSOL Energy and us, issuances of additional voting securities and the election of directors. When the interests of CONSOL Energy diverge from our interests, CONSOL Energy may exercise its substantial influence and control over us in favor of its own interests over our interests. Our certificate of incorporation and the master cooperation and safety agreement entitle CONSOL Energy to various corporate opportunities which might otherwise have belonged to us and relieve CONSOL Energy and its directors, officers and employees from owing us fiduciary duties with respect to such opportunities.

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

We have entered into agreements with CONSOL Energy which govern various transactions between us and our ongoing relationship, including registration rights, tax sharing and indemnification. All of these agreements were entered into while we were a wholly-owned subsidiary of CONSOL Energy, and were negotiated in the overall context of CONSOL Energy creating CNX Gas. As a result, these agreements were not negotiated at arm’s-length. Accordingly, certain rights of CONSOL Energy, particularly the rights relating to the number of demand and piggy-back registration rights that CONSOL Energy will have, the assumption by us of the registration expenses related to the exercise of these rights, our indemnification of CONSOL Energy for certain liabilities under these agreements, our payment of taxes and the retention of tax attributes may be more favorable to CONSOL Energy than if the agreements had been the subject of independent negotiation. We and CONSOL Energy and its other affiliates may enter into other material transactions and agreements from time to time in the future which also may not be deemed to be independently negotiated.

Our agreements with CONSOL Energy may limit our ability to obtain capital, make acquisitions or effect other business combinations.

Our business strategy anticipates future acquisitions of natural gas and oil properties and companies. Any acquisition that we undertake would be subject to the limitations and restrictions set forth in our agreements with CONSOL Energy and could be subject to our ability to access capital from outside sources on acceptable terms through the issuance of our common stock or other securities.

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

We and CONSOL Energy are obligated to indemnify each other for certain matters as set forth in our agreements with CONSOL Energy. As a result, any claims made against us that are properly attributable to CONSOL Energy (or conversely, claims against CONSOL Energy that are properly attributable to us) in accordance with these arrangements could require us or CONSOL Energy to exercise our respective rights under the master separation agreement and the master cooperation and safety agreement. In addition, we have an agreement with CONSOL Energy that we will refrain from taking certain actions that would result in CONSOL Energy being in default under its debt instruments. Those debt instruments currently contain covenants that would be breached if we borrow from a third party unless we contemporaneously guaranteed indebtedness of CONSOL Energy under those debt instruments. In addition, those debt instruments contain covenants that would be breached by our granting liens on certain assets unless we contemporaneously grant a pari passu lien securing the indebtedness of CONSOL Energy under those debt instruments. In connection with our obtaining an unsecured credit facility with a group of commercial lenders, we guaranteed CONSOL Energy’s $250,000 7.875% notes due March 1, 2012. We are exposed to the risk that, in these circumstances, CONSOL Energy cannot, or will not, make the required payment or in turn that we are required to make a required payment to CONSOL Energy. If this were to occur, our business and financial performance could be adversely affected.

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

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

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

In many places where we extract CBM, the coal estate is dominant. Where our principal stockholder conducts mining activity, CONSOL Energy could exercise its rights to determine when and where certain drilling 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 may lose certain synergistic advantages by separating ourselves from our current owner.

Because approximately 13.5% of our gas production is associated with active mining activities and 16.0% is associated with previously mined areas by our principal stockholder, coordination between mining and gas operations can optimize overall energy production. If CONSOL Energy were to dispose of a significant interest in us, coordination between us and CONSOL Energy’s mining subsidiaries may be more difficult to accomplish.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None

ITEM 2. PROPERTIES

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

ITEM 3. LEGAL PROCEEDINGS

On February 14, 2007, GeoMet, Inc. and certain of its affiliates filed a lawsuit against CNX Gas Company LLC and Island Creek Coal Company in the Circuit Court for the County of Tazewell, Virginia. CNX Gas has not formally been served with this lawsuit. The lawsuit alleges that CNX Gas conspired and has violated the Virginia Antitrust Act and has tortiously interfered with GeoMet’s contractual relations, prospective contracts and business expectancies. GeoMet seeks injunctive relief, actual damages of $561,000, treble damages and punitive damages in the amount of $350. CNX Gas believes this lawsuit to be without merit and intends to vigorously defend it.

CNX Gas is currently undergoing an audit by Buchanan County, Virginia local taxing authorities for the tax years 1998 through 2004. To date, the County auditors have completed review of the 1998 through 2001 period; as of December 31, 2006, we continued to receive requests relating to the 2002 through 2004 period. For each of these years from 1998 through 2004, CNX Gas has filed appropriate returns and has paid applicable license taxes based on wellhead price calculations. The audit is ongoing with no resolution being proposed by Buchanan County as of December 31, 2006. Additionally, on April 29, 2005, Buchanan County, Virginia (through its Board of Supervisors and Commissioner of Revenue) filed a “Motion for Judgment Pursuant to the Declaratory Judgment Act Virginia Code §8.01-184” against us in the Circuit Court of the County of Buchanan (At Law No. CL05000149-00) for the year 2002. The complaint alleges that we failed to properly calculate the amount of license taxes we owed to Buchanan County related to our production and sale of CBM gas in Buchanan County. Buchanan County is seeking a determination by the court that we have calculated, and continue to calculate, the license tax in an improper manner. We have continued to pay Buchanan County taxes based on our method of calculating the taxes. However, we have been accruing an additional liability on our balance sheet in an amount based on the difference between our calculation of the tax and Buchanan County’s calculation. We believe that we have calculated the tax correctly and in accordance with the applicable rules and regulations of Buchanan County and intend to vigorously defend our position. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations, or cash flows.

In October 2005, CDX Gas, LLC (CDX) alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX demanded that we enter into a business arrangement with CDX to use its patented technology. Alternatively, CDX informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly covered by their patents. We believe that approximately 31 of our producing wells to date could be covered by their claim. We deny all of these allegations and we are vigorously contesting them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania (C.A. No. 05-1574), seeking a judicial determination that we do not infringe any claim of any valid and enforceable CDX patent. CDX filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain claims of their patents. A hearing was held before a Court-appointed Special Master with regard to the scope of the asserted CDX patents and the Special Master’s report and recommendations was adopted by order of the Court on October 13, 2006. As a result of that order and subject to appellate review, certain of our wells may be found to infringe certain of the CDX claims of the patents in suit, if those patents are ultimately determined to be valid and enforceable. The report of CDX’s damages expert suggests that CDX will seek (i) reasonable royalty damages on production from allegedly infringing wells at a royalty rate of 10%, or approximately $1,900, based on projected production through June 2007, and (ii) “lost profits” damages of approximately $23,600 for allegedly infringing wells drilled though August 2006, which assumes that CNX Gas would have no choice but to have entered into a joint operating arrangement with CDX. We believe that there is no basis in the law for this “lost profits” theory. We continue to believe that we do not infringe any properly construed claim of any valid, enforceable patent. We cannot predict the ultimate outcome of this lawsuit; however, CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations or cash flows.

In 2004, Yukon Pocahontas Coal Company, Buchanan Coal Company, and Sayers-Pocahontas Coal Company filed a complaint against Consolidation Coal Company (“CCC”), a subsidiary of CONSOL Energy in the Circuit Court of Buchanan County, Virginia, seeking damages and injunctive relief in connection with the deposit of untreated water from mining activities at CCC’s Buchanan Mine into nearby void spaces in the mine of one of CONSOL Energy’s other subsidiaries, Island Creek Coal Company (“ICCC”). CCC believes that it had, and continues to have, the right to store water in these void areas. On September 21, 2006, the plaintiffs filed an amended complaint in the Circuit Court of Buchanan County, Virginia (Case No. CL04-91) which, among other things, added CONSOL Energy, ICCC and CNX Gas Company LLC as additional defendants. The amended complaint alleges, among other things, that CNX Gas Company LLC, as lessee and operator under certain coalbed methane gas leases from plaintiffs, had a duty to prevent CCC from depositing water into the mine voids and failed to do so. The proposed amended complaint seeks $150,000 in damages from the additional defendants, plus costs, interest and attorneys’ fees. CNX Gas Company LLC denies that it has any liability in this matter and intends to vigorously defend this action.

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

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

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

None.

PART II


ITEM 5.		MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The shares of CNX Gas Corporation common stock are listed and traded on the New York Stock Exchange (“NYSE”), under the symbol “CXG”. Our common stock began trading on January 19, 2006, following the effectiveness of our resale registration statement on Form S-1.

The quarterly high and low share price for CNX Gas stock was as follows for the 2006 quarters ended:


	High		Low
March 31	$	26.50	$	20.13
June 30	$	32.99	$	24.50
September 30	$	30.10	$	21.84
December 31	$	28.47	$	22.12

As of December 31, 2006 there were 10 holders of record of the Company’s common stock; we believe that there are significantly more beneficial holders of our stock.

STOCK PERFORMANCE GRAPH

The following performance graph compares the cumulative shareholders’ return on the common stock of CNX Gas Corporation (CXG) to the cumulative return for the same period of the S&P Oil and Gas Exploration and Production index and the S&P MidCap 400 Index. The chart below was structured in a monthly format rather than yearly because CNX Gas has only been a public company since January 2006.

The graph assumes that the value of the investment in CNX Gas common stock and each index was $100 at January 19, 2006 (the date CNX Gas’ shares were listed on the NYSE). The graph also assumes that all dividends, if any, were reinvested and that investments were held through December 31, 2006.



	Base Period										Months Ending

Company / Index	Jan-19-06		Jan-06		Feb-06		Mar-06		Apr-06		May-06		Jun-06		Jul-06		Aug-06		Sep-06		Oct-06		Nov-06		Dec-06
CNX Gas Corporation		100		106.93		95.73		115.56		126.67		126.40		133.33		120.27		114.71		102.98		116.22		123.56		113.33
S&P MidCap 400 Index		100		101.24		100.39		102.89		104.34		99.64		99.66		96.82		97.92		98.58		102.68		105.98		105.47
S&P Oil & Gas Exploration & Production		100		101.81		90.92		93.20		95.12		91.01		96.25		100.04		95.76		92.46		98.21		105.52		95.84

COMPARISON OF CUMMULATIVE TOTAL RETURN

The foregoing graph shall not be deemed to be filed as part of the Form 10-K and does not constitute soliciting material and should not be deemed filed or incorporated by reference into any other filing of CNX Gas under the Securities Act of 1933 or the Securities Exchange Act of 1934, except to the extent CNX specifically incorporates the graph by reference.

We currently retain our earnings for the development of our business and do not expect to pay any cash dividends. Other than the special dividend of approximately $420,200 we paid to CONSOL Energy with the net proceeds from the private placement of the shares of CNX Gas described below, we have not paid any cash dividends from the date of our inception.

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

Recent Sales of Unregistered Securities

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

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

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

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

(4) On August 11, 2005, following the exercise by FBR of an over-allotment option in connection with the above referenced private placement, we completed the sale of 3,643,913 shares of common stock, 822,702 of which were offered and sold to qualified institutional buyers pursuant to Rule 144A under the Securities Act, 51,300 of which were offered and sold to foreign buyers pursuant to Regulation S promulgated under the Securities Act and 2,769,911 of which were offered and sold to accredited investors pursuant Rule 506 under the Securities Act. FBR served as the initial purchaser under the Rule 144A and Regulation S offerings and served as our placement agent with respect to the Rule 506 offering. In the Rule 144A and Regulation S offerings, we sold the securities to FBR at a price of $15.04 per share, which was a $0.96 per share discount over the gross offering price to the investors of $16.00 per share. In the Rule 506 offering, we sold shares to the investors at $16.00 per share and paid FBR a $0.96 per share commission. Aggregate net proceeds to CNX Gas for the total offering, after deducting discounts and commissions of $3,498 was $54,804. CNX Gas relied on subscription agreements and associated questionnaires in order to satisfy itself that the requirements of Rule 144A, Regulation S and Rule 506, as applicable, were satisfied. All net proceeds of the above offering were paid to Consolidation Coal Company as a special dividend.

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

The registration statement on Form S-1 (SEC File No. 333-127483), as amended, filed by the Company was declared effective by the Securities and Exchange Commission on January 18, 2006. CNX Gas registered for sale 27,936,667 shares of common stock, all of which were held by selling stockholders named in the registration statement. Under the registration statement, the shares can be offered and sold by the selling stockholders in one or more transactions at fixed prices, prevailing market prices or negotiated prices. CNX Gas did not sell any shares for our own account and did not receive any proceeds from the sale of securities by any selling stockholders. CNX Gas incurred expenses as detailed in the registration statement of approximately $1,170.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents our selected consolidated financial and operating data for, and as of the end of, each of the periods indicated. The selected consolidated financial data for, and as of the end of, each of the twelve months ended December 31, 2006, 2005, 2004, and 2003 are derived from our audited consolidated financial statements, including the consolidated balance sheets at December 31, 2006 and 2005 and the related consolidated statements of income and cash flows for each of the twelve months ended December 31, 2006, 2005, 2004, and 2003, and the notes thereto appearing herein. The selected consolidated financial data for, and as of the end of, the twelve months ended December 31, 2002 is derived from our unaudited consolidated financial statements, and in the opinion of management include all adjustments, consisting only of normal recurring accruals, that are necessary for a fair presentation of our financial position and operating results for these periods. The selected consolidated financial and operating data are not necessarily indicative of the results that may be expected for any future period. The selected consolidated financial and operating data should be read in conjunction with “Management’s Discussion and Analysis of Results of Operations and Financial Condition” and the financial statements and related notes included in this Annual Report.

CNX GAS CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME


STATEMENTS OF INCOME DATA	Twelve Months Ended December 31,
(In thousands)	2006		2005		2004		2003		2002
RESULTS OF OPERATIONS
Outside Sales	$	385,056	$	277,031	$	214,721	$	145,884	$	119,463
Related Party Sales		8,490		6,052		22,036		32,572		9,542
Royalty Interest Gas Sales		51,054		45,351		41,858		32,442		19,880
Purchased Gas Sales		43,973		275,148		112,005		—		—
Other Income		25,286		9,859		6,916		4,485		2,068

TOTAL REVENUE AND OTHER INCOME		513,859		613,441		397,536		215,383		150,953

Lifting Costs		31,096		26,794		23,939		20,761		16,297
Gathering and Compression Costs		55,091		40,623		37,021		28,914		24,749
Royalty Interest Gas Costs		41,998		36,641		32,914		24,200		12,214
Purchased Gas Costs		44,843		278,720		113,063		—		—
Other		6,868		9,721		9,494		15,902		11,909
General and Administrative		38,654		19,171		15,530		11,995		8,712
Depreciation, Depletion and Amortization		37,999		35,039		32,889		33,600		34,368
Interest Expense		870		14		—		—		—

TOTAL COSTS AND EXPENSES		257,419		446,723		264,850		135,372		108,249

Earnings Before Income Taxes and Cumulative Effect of Change in Accounting Principle		256,440		166,718		132,686		80,011		42,704
Income Taxes		96,573		64,550		51,898		31,202		16,677

Earnings Before Cumulative Effect of Change in Accounting Principle		159,867		102,168		80,788		48,809		26,027
Cumulative Effect of Change in Accounting for Gas Well Plugging Costs (Net of Tax Impact of $1,879)		—		—		—		2,905		—

NET INCOME	$	159,867	$	102,168	$	80,788	$	51,714	$	26,027

Earnings Per Share from Continuing Operations:
Basic	$	1.06	$	0.76	$	0.66	$	0.40	$	0.21

Diluted	$	1.06	$	0.76	$	0.66	$	0.40	$	0.21

Earnings Per Share from Net Income:
Basic	$	1.06	$	0.76	$	0.66	$	0.42	$	0.21

Diluted	$	1.06	$	0.76	$	0.66	$	0.42	$	0.21

Weighted Average Number of Common Shares Outstanding:
Basic		150,845,518		134,071,334		122,896,667		122,896,667		122,896,667

Dilutive		151,017,456		134,137,219		122,988,359		122,988,359		122,988,359


BALANCE SHEETS DATA	As of December 31,
(In thousands)	2006		2005		2004			2003			2002
Working Capital (Deficiency)	$	115,824	$	3,720	$	(35,030	)	$	(7,971	)	$	2,868
Total Assets		1,155,001		859,167		718,859			664,635			598,236
Capital Lease Obligation (Including current portion)		66,470		—		—			—			—
Total Deferred Credits and Other Liabilities		153,977		109,226		205,614			170,520			114,902
Stockholders’ Equity		880,215		679,472		462,556			464,232			468,617


	Twelve Months
CASH FLOW STATEMENTS DATA	Ended December 31,
(In thousands)	2006			2005			2004			2003			2002
Net Cash Provided by Operating Activities	$	243,569		$	144,997		$	175,350		$	143,133		$	88,643
Net Cash (Used in) Investing Activities		(156,020	)		(108,287	)		(93,114	)		(90,605	)		(101,472	)
Net Cash (Used in) Provided by Financing Activities		(449	)		(16,640	)		(82,237	)		(52,526	)		12,831


	Twelve Months
	Ended December 31,
OTHER OPERATING DATA	2006		2005		2004		2003		2002
Net Sales Volumes (Bcf) ⁽¹⁾		56.14		48.39		48.56		44.46		41.30
Average Sales Price Including Effects of Financial Settlements ($ per Mcf) ⁽¹⁾⁽²⁾	$	7.04	$	5.90	$	4.90	$	4.03	$	3.13
Total Average Costs ($ Per Mcf) ⁽¹⁾	$	3.02	$	2.72	$	2.45	$	2.43	$	2.25
Net Estimated Proved Reserves (Bcfe) ⁽¹⁾⁽³⁾		1,265		1,130		1,045		1,004		961


	Twelve Months
OTHER FINANCIAL DATA	Ended December 31,
(In thousands)	2006		2005		2004		2003		2002
Capital Expenditures	$	154,243	$	110,752	$	89,753	$	83,869	$	61,705
EBIT ⁽⁴⁾		253,857		166,314		132,686		80,011		42,704
EBITDA ⁽⁴⁾		291,856		201,353		165,575		113,611		77,072


(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 is included in the equity earnings data in 2006, 2005, 2004, 2003 and part of 2002. Greene Energy is included in the equity earnings in 2002. Sales of gas produced by equity affiliates were 0.22 Bcf for the twelve months ended December 2006, 0.23 Bcf for the twelve months ended December 31, 2005, 0.20 Bcf for the twelve months ended December 31, 2004, 0.08 Bcf for the twelve months ended December 31, 2003 and 0.22 Bcf for the twelve months ended December 31, 2002.

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

(3)		Represents proved developed and proved undeveloped gas reserves at period end for total operations including equity affiliates, which are immaterial.

(4)		EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with accounting principles generally accepted in the United States of America, management believes that they are useful to an investor in evaluating CNX Gas because they are used as measures to evaluate a company’s operating performance before debt expense and cash flow. EBIT and EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as substitute for measures of performance in accordance with accounting principles generally accepted in the United States of America. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to other similarly titled measures of other companies. Management’s discretionary use of funds depicted by EBIT and EBITDA may be limited by working capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconciliation of EBIT and EBITDA to financial net income is as follows:


	Twelve Months
	Ended December 31,
(In thousands)	2006		2005		2004		2003		2002
Net Income	$	159,867	$	102,168	$	80,788	$	51,714	$	26,027
Add: Interest Expense		870		14		—		—		—
Less: Interest Income		3,453		418		—		—		—
Less: Cumulative Effect of Changes in Accounting for Gas Well Plugging Costs, Net of Income Taxes of $1,879		—		—		—		2,905		—
Add: Income Tax Expense		96,573		64,550		51,898		31,202		16,677


Earnings Before Net Interest and Taxes (EBIT)		253,857		166,314		132,686		80,011		42,704
Add: Depreciation, Depletion and Amortization		37,999		35,039		32,889		33,600		34,368

Earnings Before Net Interest, Taxes and Depreciation, Depletion and Amortization (EBITDA)	$	291,856	$	201,353	$	165,575	$	113,611	$	77,072

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

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

Overview

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

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

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

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

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

The success of our operations substantially depends upon rights we received from CONSOL Energy as a part of our separation. CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of their ownership or rights to CBM and natural gas and certain related surface rights. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with their coal mining activity. These rights are not dependent upon any continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will, among other things, provide us certain corporate staff services and coordinate our tax filings.

In August 2005, CNX Gas sold 27.9 million shares in a private placement transaction. The aggregate net proceeds of the transaction (approximately $420,200) were used to pay a special dividend to CONSOL Energy. CONSOL Energy continues to beneficially own 81.5% of our outstanding common stock.

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

Our goal is to create shareholder value by efficiently increasing production and adding reserves, with a continued emphasis on safety. We believe that by working safely, we can enhance our productivity and continue to be a cost leader in the industry. During 2006, we achieved the following:

•

completed another year with no employee-related lost time accident. We have accumulated over 2 million man hours without a lost time accident;

	•		increased our 2006 production by 16.0% from 2005 to 56 Bcf, despite capacity constraints on the Columbia pipeline;

	•		generated net income of nearly $160,000 and increased our cash balance by $87,000 to $107,000;

	•		increased our proved reserve base by replacing 340.0% of our production;

	•		brought more than 250 additional wells online;

	•		maintained our low cost structure relative to our peer group;

	•		entered into a 15-year transportation agreement on the Jewell Ridge Pipeline in October 2006 to provide an additional outlet for our production;

	•		significantly increased our operations in our Mountaineer CBM play in Northern Appalachia and began operations in two new areas – Nittany, a CBM play in Central Pennsylvania and Cardinal, a New Albany shale play in the Illinois Basin; and

	•		invested in the infrastructure necessary for continued growth, including increased staffing, a new information management software platform and a new long-term incentive compensation program that directly aligns the interests of our managers with the interests of our shareholders.

Outlook

In 2007, we expect to produce 64 Bcf of gas.

Our 2007 capital expenditures are projected to be $312,000. This capital budget includes significant infrastructure capital that is required for the company to achieve its strategic vision of producing 100 Bcf per year by 2010. CNX Gas will continue to re-invest in its core business as long as it can achieve expected rates of return that exceed its weighted average cost of capital.

In 2007, we expect to drill a total of 401 wells that consist of 278 in Virginia, 55 in Tennessee and other areas, 57 in Mountaineer, 8 in Nittany, and 3 in Cardinal.

Results of Operations

Twelve Months Ended December 31, 2006 compared with Twelve Months Ended December 31, 2005
(Amounts reported in thousands)

Net Income

Net income changed primarily due to the following items:


					Dollar			Percentage
	2006		2005		Variance			Change
Revenue and Other Income:
Outside Sales	$	385,056	$	277,031	$	108,025			39.0	%
Related Party Sales		8,490		6,052		2,438			40.3	%
Royalty Interest Gas Sales		51,054		45,351		5,703			12.6	%
Purchased Gas Sales		43,973		275,148		(231,175	)		(84.0	)%
Other Income		25,286		9,859		15,427			156.5	%

Total Revenue and Other Income		513,859		613,441		(99,582	)		(16.2	)%

Costs and Expenses:
Lifting Costs		31,096		26,794		4,302			16.1	%
Gathering and Compression Costs		55,091		40,623		14,468			35.6	%
Royalty Interest Gas Costs		41,998		36,641		5,357			14.6	%
Purchased Gas Costs		44,843		278,720		(233,877	)		(83.9	)%
Other		6,868		9,721		(2,853	)		(29.3	)%
General and Administrative		38,654		19,171		19,483			101.6	%
Depreciation, Depletion and Amortization		37,999		35,039		2,960			8.4	%
Interest Expense		870		14		856			6,114.3	%

Total Costs and Expenses		257,419		446,723		(189,304	)		(42.4	)%

Earnings Before Income Taxes		256,440		166,718		89,722			53.8	%
Income Taxes		96,573		64,550		32,023			49.6	%

Net Income	$	159,867	$	102,168	$	57,699			56.5	%

Net income for 2006 was improved primarily due to increases in average sales price and production.

Revenue and Other Income

Revenue and other income decreased due to the following items:


					Dollar			Percentage
	2006		2005		Variance			Change
Revenue and Other Income:
Outside Sales	$	385,056	$	277,031	$	108,025			39.0	%
Related Party Sales		8,490		6,052		2,438			40.3	%
Royalty Interest Gas Sales		51,054		45,351		5,703			12.6	%
Purchased Gas Sales		43,973		275,148		(231,175	)		(84.0	)%
Other Income		25,286		9,859		15,427			156.5	%

Total Revenue and Other Income	$	513,859	$	613,441	$	(99,582	)		(16.2	)%

The increase in outside sales, related party sales, and royalty interest gas sales was primarily due to increased production and average sales price in 2006 compared to 2005. Both purchased gas sales and purchased gas costs have decreased in the current period as a result of the adoption of a new accounting standard effective January 1, 2006. This reduction is the result of applying Emerging Issues Task Force No. 04-13 “Accounting for Purchases and Sales of Inventory with the same Counterparty” (EITF 04-13) in the current year, which requires the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. Other income increased as a result of insurance recoveries for losses we sustained from prior year CONSOL Energy mining incidents. It also increased due to additional royalty income and an increase in interest income as a result of the increase to our cash balance throughout the current year.


							Percentage
	2006		2005		Variance		Change
Sales Volumes (Bcf)		55.9		48.2		7.7		16.0	%
Average Sales Price (per Mcf)	$	7.04	$	5.88	$	1.16		19.7	%

The increase in average sales price is primarily the result of selling the majority of our current year production at market rates that were higher than the prices we sold our gas under hedging contracts in the prior year. CNX Gas enters into physical gas supply transactions with various counterparties for terms varying in length. CNX Gas has also entered into financial gas swap transactions that qualify as financial cash flow hedges. These financial gas swap transactions exist parallel to the underlying physical transactions. These physical and financial hedges represented approximately 27% of our produced gas sales volumes for the twelve months ended December 31, 2006 at an average price of $7.42 per Mcf. In the prior year these hedges represented approximately 70% at an average price of $4.77 per Mcf.


								Percentage
	2006		2005		Variance			Change
Royalty Interest Gas Sales Volumes (Bcf)		7.6		6.6		1.0			15.2	%
Average Sales Price (per Mcf)	$	6.76	$	6.92	$	(0.16	)		(2.3	)%

Included in royalty interest gas sales are the revenues related to the portion of production associated with royalty interest owners. The decrease in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions, being higher in the prior year than in the current year. Volumes increased as a result of our current year drilling program.


								Percentage
	2006		2005		Variance			Change
Purchased Gas Sales Volumes (Bcf)		6.1		28.7		(22.6	)		(78.7	)%
Average Sales Price (per Mcf)	$	7.20	$	9.59	$	(2.39	)		(24.9	)%

Included in purchased gas sales revenue are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia Gas Transmission Corporation (TCO) pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 on January 1, 2006, purchased gas sales and volumes have decreased. The net result for transactions that meet the above criteria is reflected in transportation expense in the current year. Additionally, there are small volumes of gas we purchase from third party producers at market prices less our gathering charge, which we then resell.

Other income consists of the following items:


					Dollar			Percentage
	2006		2005		Variance			Change
Royalty Income	$	10,230	$	8,158	$	2,072			25.4	%
Insurance Proceeds		10,165		—		10,165			100.0	%
Interest Income		3,453		418		3,035			726.1	%
Third Party Gathering Revenue		1,341		1,110		231			20.8	%
Other Miscellaneous		97		173		(76	)		(43.9	)%

Total Other Income	$	25,286	$	9,859	$	15,427			156.5	%

Royalty income increased in 2006 compared to 2005 due to increased gas prices and additional production on existing contracts. Royalty income received from third parties is calculated as a percentage of the third parties sales price.

Insurance proceeds relate to the settlement of claims for losses we sustained from CONSOL Energy mining incidents that adversely affected our gob gas production in 2005.

Interest income increased in 2006 as a result of increased earnings and the fact that CNX Gas retained cash collections as a separate stand alone company for the entire year. For most of 2005, CNX Gas was part of CONSOL Energy and only retained cash after separation from CONSOL Energy.

Costs and Expenses

Both purchased gas sales and purchased gas costs have decreased in the current period as a result of the adoption of a new accounting standard effective January 1, 2006. This reduction is the result of applying EITF 04-13 in the current year, which requires the combining of matching buy/sell transactions, done in contemplation of one another, that were committed to on or after January 1, 2006. Separate from the effects of the accounting change described above, firm transportation costs, administrative expense and costs associated with increased production are higher and are made up of the following components:


					Dollar			Percentage
	2006		2005		Variance			Change
Costs and Expenses:
Lifting Costs	$	31,096	$	26,794	$	4,302			16.1	%
Gathering and Compression Costs		55,091		40,623		14,468			35.6	%
Royalty Interest Gas Costs		41,998		36,641		5,357			14.6	%
Purchased Gas Costs		44,843		278,720		(233,877	)		(83.9	)%
Other		6,868		9,721		(2,853	)		(29.3	)%
General and Administrative		38,654		19,171		19,483			101.6	%
Depreciation, Depletion and Amortization		37,999		35,039		2,960			8.4	%
Interest Expense		870		14		856			6,114.3	%

Total Costs and Expenses	$	257,419	$	446,723	$	(189,304	)		(42.4	)%


							Percentage
	2006		2005		Variance		Change
Sales Volumes (Bcf)		55.9		48.2		7.7		16.0	%
Average Lifting Costs (per Mcf)	$	0.56	$	0.56	$	—		0.0	%

Lifting costs per Mcf remained flat due to increased production from our ongoing drilling program. Slightly higher production taxes, as a result of higher pricing, were offset by savings in well service costs on a per Mcf basis.


							Percentage
	2006		2005		Variance		Change
Sales Volumes (Bcf)		55.9		48.2		7.7		16.0	%
Average Gathering and Compression Costs (per Mcf)	$	0.99	$	0.84	$	0.15		17.9	%

The increase in gathering and compression costs per unit was attributable to an additional $0.07 per Mcf charge for the purchase of firm transportation capacity on the Columbia pipeline acquired to ensure deliverability of our gas. Due to the application of EITF 04-13, the combining of matching buy/sell transactions accounts for an additional $0.06 per Mcf increase in the current period. Although the net costs associated with similar buy/sell transactions were incurred during the prior period, they were not recorded as part of gathering and compression costs. Instead, they were recorded on a gross basis as purchased gas sales and purchased gas costs. Gathering and compression costs have also increased approximately $0.05 per Mcf due to additional power expenses related to both increased megawatt hour rates charged by our power provider and the use of more electric compressors during the current year that were previously powered by gas for most of the prior year. Maintenance and various other related transactions have decreased $0.03 per Mcf as a result of increased production and the compressor conversions. The sales production used to calculate this unit cost does not include volumes from third parties flowing on our lines.


								Percentage
	2006		2005		Variance			Change
Royalty Interest Gas Sales Volumes (Bcf)		7.6		6.6		1.0			15.2	%
Average Cost (per Mcf)	$	5.56	$	5.59	$	(0.03	)		(0.5	)%

Included in royalty interest gas costs are the expenses related to the portion of production associated with royalty interest owners. The decrease in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions, being higher in the prior year than in the current year. Volumes increased as a result of additional wells coming online from our on-going drilling program.


								Percentage
	2006		2005		Variance			Change
Purchased Gas Cost Volumes (Bcf)		6.1		28.7		(22.6	)		(78.7	)%
Average Purchased Gas Costs (per Mcf)	$	7.34	$	9.71	$	(2.37	)		(24.4	)%

Included in purchased gas costs are volumes of gas we simultaneously purchased from and sold to the same counterparties between the segmentation and interruptible pools on the Columbia pipeline in order to satisfy obligations to certain customers. In accordance with Emerging Issues Task Force Issue No. 99-19 “Reporting Revenue Gross as a Principal versus Net as an Agent” (EITF 99-19), we have historically recorded our revenues and our costs on a gross basis. However, because we adopted EITF 04-13 on January 1, 2006, purchased gas costs and volumes have decreased. The net result for transactions that meet the above criteria is reflected in transportation expense in the current year.

Other costs and expenses decreased due to the following items:


						Dollar			Percentage
	2006			2005		Variance			Change
Well Site General Maintenance	$	3,750		$	3,781	$	(31	)		(0.8	)%
Gob Collection Costs		3,012			3,280		(268	)		(8.2	)%
Land Broker Fees		1,156			977		179			18.3	%
Land Rentals		576			635		(59	)		(9.3	)%
Imbalance		(648	)		899		(1,547	)		(172.1	)%
Equity in (Earnings) Loss of Affiliates		(978	)		149		(1,127	)		(756.4	)%

Total Other Costs and Expenses	$	6,868		$	9,721	$	(2,853	)		(29.3	)%

Well site general maintenance costs from the on-going drilling program were generally flat, despite increased production and drilling.

Gob collection costs decreased slightly in 2006 due to the reduced number of gob wells drilled because of the idling of the CONSOL Energy VP-8 mine.

The gas imbalance has shifted from an under-delivered position in 2005 to an over-delivered position in 2006, and therefore resulted in income for 2006 compared to expense in 2005. Because contracted quantities of gas delivered to the pipeline rarely equal physical deliveries to customers, CNX Gas is responsible for monitoring this imbalance and requesting adjustments to contracted volumes as circumstances warrant. This decrease in imbalance cost was offset by corresponding decreases in gas sales revenue.

Equity in (earnings) loss of affiliates improved in 2006 compared to 2005 because Knox Energy had higher earnings in 2006 compared to 2005 primarily due to production increases at the joint venture and additional service revenue. Buchanan Generation’s incurred losses that were higher in the current year primarily due to the facility being run for less megawatt hours in 2006 compared to 2005.

General and administrative costs increased to $38,654 in 2006 from $19,171 in 2005 primarily due to additional costs related to becoming a separate publicly traded company as a result of the separation of CNX Gas from CONSOL Energy. These increased costs include additional staffing and facilities, incentive compensation plans, stock option plans, legal and accounting fees, Sarbanes-Oxley compliance fees, implementation fees for the information management software platform and various other service costs.

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


					Dollar		Percentage
	2006		2005		Variance		Change
Production	$	24,668	$	23,531	$	1,137		4.8	%
Gathering		13,331		11,508		1,823		15.8	%

Total Depreciation, Depletion and Amortization	$	37,999	$	35,039	$	2,960		8.4	%

The increase in production related depreciation, depletion and amortization is due to the net effect of additional volumes in the current year and a slightly lower unit-of-production rate in 2006 compared to 2005. Rates are generally calculated using the net book value of assets on January 1^st divided by proved developed reserves. Gathering depreciation, depletion and amortization is recorded on the straight-line method and increased due to additional assets being placed in service in 2006, including the effect of the Jewell Ridge lateral.

Interest expense increased as a result of the imputed interest associated with recording the Jewell Ridge lateral arrangement as a capital lease for financial accounting and reporting purposes.

Income Taxes


										Percentage
	2006			2005			Variance			Change
Earnings Before Income Taxes	$	256,440		$	166,718		$	89,722			53.8	%
Tax Expense	$	96,573		$	64,550		$	32,023			49.6	%
Effective Income Tax Rate		37.7	%		38.7	%		(1.0	)%

CNX Gas’ effective tax rate decreased in 2006 primarily due to a reduction in state tax rates.

Issues Regarding Coal Mining Activities

A portion of our gas production is associated with coal mining activities at CONSOL Energy’s Buchanan Mine. These mining activities require the removal of water from the mine and the ventilation of the mine. Several lawsuits and permit appeals have been filed that could affect the removal of water from the mine. Separately, a lawsuit has been filed with respect to a ventilation fan that could affect the ventilation of the mine. If operations at CONSOL Energy’s Buchanan Mine are adversely affected as a result of these legal proceedings, our gas production relating to mining activities would be adversely affected.

Twelve Months Ended December 31, 2005 compared with Twelve Months Ended December 31, 2004
(Amounts reported in thousands)

Net Income

Net income changed primarily due to the following items:


					Dollar			Percentage
	2005		2004		Variance			Change
Revenue and Other Income:
Outside Sales	$	277,031	$	214,721	$	62,310			29.0	%
Related Party Sales		6,052		22,036		(15,984	)		(72.5	)%
Royalty Interest Gas Sales		45,351		41,858		3,493			8.3	%
Purchased Gas Sales		275,148		112,005		163,143			145.7	%
Other Income		9,859		6,916		2,943			42.6	%

Total Revenue and Other Income		613,441		397,536		215,905			54.3	%

Costs and Expenses:
Lifting Costs		26,794		23,939		2,855			11.9	%
Gathering and Compression Costs		40,623		37,021		3,602			9.7	%
Royalty Interest Gas Costs		36,641		32,914		3,727			11.3	%
Purchased Gas Costs		278,720		113,063		165,657			146.5	%
Other		9,721		9,494		227			2.4	%
General and Administrative		19,171		15,530		3,641			23.4	%
Depreciation, Depletion and Amortization		35,039		32,889		2,150			6.5	%
Interest Expense		14		—		14			100.0	%

Total Costs and Expenses		446,723		264,850		181,873			68.7	%

Earnings Before Income Taxes		166,718		132,686		34,032			25.6	%
Income Taxes		64,550		51,898		12,652			24.4	%

Net Income	$	102,168	$	80,788	$	21,380			26.5	%

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

Revenue and Other Income

Revenue and other income increased due to the following items:


					Dollar			Percentage
	2005		2004		Variance			Change
Revenue and Other Income:
Outside Sales	$	277,031	$	214,721	$	62,310			29.0	%
Related Party Sales		6,052		22,036		(15,984	)		(72.5	)%
Royalty Interest Gas Sales		45,351		41,858		3,493			8.3	%
Purchased Gas Sales		275,148		112,005		163,143			145.7	%
Other Income		9,859		6,916		2,943			42.6	%

Total Revenue and Other Income	$	613,441	$	397,536	$	215,905			54.3	%

The increase in outside sales revenue was primarily due to a higher average sales price per thousand cubic feet in 2005 compared to 2004. Related party sales decreased due to the impacts of the Buchanan mine incidents. Royalty interest gas sales increased due to increased prices. Purchased gas sales revenue increased due to the additional matching buy/sell arrangements required to sell our gas. Other income increased due to increased royalty income, increased third party gathering revenue, increased interest income and other miscellaneous income.


								Percentage
	2005		2004		Variance			Change
Sales Volumes (Bcf)		48.2		48.4		(0.2	)		(0.4	)%
Average Sales Price (per Mcf)	$	5.88	$	4.90	$	0.98			20.0	%

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

As a result of increased demand for pipeline use on the Columbia interstate pipeline and the potential for curtailment on portions of the shipment capacity allocated to CNX Gas, we purchased firm transportation capacity on the pipeline during 2005. This arrangement offset a portion of the expected impact from periodic curtailments. In April 2005, CNX Gas was given notice by Columbia regarding reductions in allowable gas flows due to routine maintenance and construction activities. Interruptible gas was completely shut in and our contracted firm transportation flows were reduced by 60%, which resulted in reduced revenues of approximately $6.8 million along with other smaller curtailments throughout the year that were also eventually lifted. Although CNX Gas anticipates that these pipeline constraints will be an on-going issue for the foreseeable future, we intend to gain access to the ETNG pipeline, which is south of our Central Appalachia operations.


								Percentage
	2005		2004		Variance			Change
Royalty Interest Gas Sales Volumes (Bcf)		6.6		6.9		(0.3	)		(4.3	)%
Average Sales Price (per Mcf)	$	6.92	$	6.06	$	0.86			14.2	%

Included in royalty interest gas sales are the revenues related to the portion of production associated with royalty interest owners. The increase in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions being higher in the current year than in the prior year. Volumes decreased as a result of curtailments and maintenance related capacity constraints, which were partially offset by additional wells coming online from our on-going drilling program.


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

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

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


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

Total Other Income	$	9,859	$	6,916	$	2,943		42.6	%

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

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

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

Costs and Expenses

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


					Dollar		Percentage
	2005		2004		Variance		Change
Costs and Expenses:
Lifting Costs	$	26,794	$	23,939	$	2,855		11.9	%
Gathering and Compression Costs		40,623		37,021		3,602		9.7	%
Royalty Interest Gas Costs		36,641		32,914		3,727		11.3	%
Purchased Gas Costs		278,720		113,063		165,657		146.5	%
Other		9,721		9,494		227		2.4	%
General and Administrative		19,171		15,530		3,641		23.4	%
Depreciation, Depletion and Amortization		35,039		32,889		2,150		6.5	%
Interest Expense		14		—		14		100.0	%

Total Costs and Expenses	$	446,723	$	264,850	$	181,873		68.7	%


								Percentage
	2005		2004		Variance			Change
Sales Volumes (Bcf)		48.2		48.4		(0.2	)		(0.4	)%
Average Lifting Costs (per Mcf)	$	0.56	$	0.50	$	0.06			12.0	%

Lifting costs per unit sold increased $0.06 per Mcf in the period, of which $0.03 per Mcf was due to higher production taxes in 2005 compared to 2004 driven by higher realized sales price. Well maintenance fees increased $0.02 per Mcf due to additional wells being serviced in the current year. Various other transactions, none of which were individually material, also contributed to the increase in per unit costs.


								Percentage
	2005		2004		Variance			Change
Sales Volumes (Bcf)		48.2		48.4		(0.2	)		(0.4	)%
Average Gathering and Compression Costs (per Mcf)	$	0.84	$	0.77	$	0.07			9.1	%

The increase in gathering and compression costs per unit was attributable to an additional $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. Gathering and compression costs per unit also increased approximately $0.02 per Mcf due to additional power expense, as a result of converting several compressors from gas powered to electric powered in the current year. Gathering and compression unit costs also increased due to various other transactions, none of which were individually material.


								Percentage
	2005		2004		Variance			Change
Royalty Interest Gas Sales Volumes (Bcf)		6.6		6.9		(0.3	)		(4.3	)%
Average Cost (per Mcf)	$	5.59	$	4.76	$	0.83			17.4	%

Included in royalty interest gas costs are the expenses related to the portion of production associated with royalty interest owners. The increase in sales price is a function of the average CNX Gas price, before the effects of financial swap transactions, being higher in the current year than in the prior year. Volumes decreased as a result of curtailments and maintenance related capacity constraints, which were partially offset by additional wells coming online from our on-going drilling program.


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

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

Other costs and expenses increased due to the following items:


						Dollar			Percentage
	2005		2004			Variance			Change
Well Site General Maintenance	$	3,781	$	3,135		$	646			20.6	%
Gob Collection Costs		3,280		3,401			(121	)		(3.6	)%
Land Broker Fees		977		266			711			267.3	%
Imbalance		899		(266	)		1,165			438.0	%
Land Rentals		635		535			100			18.7	%
Equity in (Earnings) Loss of Affiliates		149		2,423			(2,274	)		(93.9	)%

Total Other Costs and Expenses	$	9,721	$	9,494		$	227			2.4	%

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

Land Broker Fees have increased due to the expanded effort to prepare/permit well sites.

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

Equity in (earnings) loss of affiliates improved in 2005 compared to 2004 because Knox Energy had earnings in 2005 compared to a loss in 2004. This is primarily due to production increases and additional service revenue. CNX Gas owns a 50% interest in this joint venture. CNX Gas’ production percentage increased due to a settlement agreement between CNX Gas and our partner in the joint venture in which CNX Gas now fully owns more wells. Prior to the settlement agreement, CNX Gas shared ownership interest in these wells proportionately with our partner. Additionally, Buchanan Generation’s losses were lower in the current year 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.

General and administrative increased to $19,171 in 2005 from $15,530 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:


					Dollar		Percentage
	2005		2004		Variance		Change
Production	$	23,531	$	22,353	$	1,178		5.3	%
Gathering		11,508		10,536		972		9.2	%

Total Depreciation, Depletion and Amortization	$	35,039	$	32,889	$	2,150		6.5	%

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

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

Income Taxes


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

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

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make judgments, estimates and assumptions that affect reported amounts of assets and liabilities in the consolidated financial statements and at the date of the financial statements, as well as the reported amounts of income and expenses during the reporting period. Note 1 of the Notes to the Consolidated Annual Financial Statements included in this Annual Report describes the significant accounting policies and methods used in the preparation of the consolidated financial statements. Actual results could differ from those estimates upon subsequent resolution of identified matters. Management believes that the estimates utilized are reasonable. The following critical accounting policies are materially impacted by judgments, assumptions and estimates used in the preparation of the consolidated financial statements.

Derivative Instruments

CNX Gas measures every derivative instrument (including certain derivative instruments embedded in other contracts) at fair value and records them on the balance sheet as either an asset or liability. Changes in fair value of derivatives are recorded currently in earnings unless special hedge accounting criteria are met. For derivatives designated as fair value hedges, the changes in fair value of both the derivative instrument and the hedged item are recorded in earnings. For derivatives designated as cash flow hedges, the effective portions of changes in fair value of the derivative are reported in other comprehensive income or loss and reclassified into earnings in the same period or periods which the forecasted transaction affects earnings. The ineffective portions of hedges are recognized in earnings in the current period.

CNX Gas formally assesses, both at inception of the hedge and on an ongoing basis, whether each derivative is highly effective in offsetting changes in fair values or cash flows of the hedged item. If it is determined that a derivative is not highly effective as a hedge or if a derivative ceases to be a highly effective hedge, CNX Gas will discontinue hedge accounting prospectively.

Stock-Based Compensation

Effective January 1, 2006, CNX Gas adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123(R), “Share-Based Payment” (SFAS 123R), using the modified prospective transition method and therefore has not restated results for prior periods. Under this transition method, stock-based compensation expense for the year ended December 31, 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS No. 123, “Accounting for Stock-Based Compensation”(SFAS 123). Stock-based compensation expense for all stock-based compensation awards granted after January 1, 2006 is based on the grant-date fair value estimated in accordance with the provisions of SFAS 123R. CNX Gas recognizes these compensation costs on a straight-line basis over the requisite service period of the award, which is generally the option vesting term. Prior to the adoption of SFAS 123R, CNX Gas recognized stock-based compensation expense in accordance with Accounting Principles Board Opinion No. 25. “Accounting for Stock Issued to Employees,” (APB 25). In March 2005, the Securities and Exchange Commission (the SEC) issued Staff Accounting Bulletin No. 107 (SAB 107) regarding the SEC’s interpretation of SFAS 123R and the valuation of share-based payments for public companies. CNX Gas has applied the provisions of SAB 107 in its adoption of SFAS 123R. See Note 11 to the Consolidated Financial Statements for a further discussion on stock-based compensation.

Effective October 11, 2006, CNX Gas adopted a long-term incentive program. This program allows for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the company’s common stock. The total number of units earned, if any, by a participant will be based on the company’s total stockholder return relative to the stockholder return of a pre-determined peer group of companies. The performance period is from October 11, 2006 to December 31, 2009. CNX Gas recognizes compensation costs on a straight-line basis over the requisite service period, based on the fair value of the PSUs. The fair value of the PSUs will be re-valued quarterly using a Monte Carlo lattice model.

Reserve Estimates

Our estimates of proved natural gas reserves and future net revenues from them are based upon reserve analyses that rely upon various assumptions, including those required by the SEC, as to natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant variance in these assumptions could materially affect the estimated quantity of our reserves. As a result, our estimates of our proved natural gas reserves are inherently imprecise. Actual future production, natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable natural gas reserves may vary substantially from our estimates contained in the reserve reports. In addition, our proved reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas prices, mechanical difficulties, governmental regulation and other factors, many of which are beyond our control.

Successful Efforts Accounting

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

Contingencies

CNX Gas is currently involved in certain legal proceedings. We have accrued our estimate of the probable costs for the resolution of these claims. This estimate has been developed in consultation with legal counsel involved in the defense of these matters and is based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. We do not believe these proceedings will have a material adverse effect on our consolidated financial position. It is possible, however, that future results of operations for any particular quarter or annual period could be materially affected by changes in our assumptions or the effectiveness of our strategies related to these proceedings.

Deferred Taxes

CNX Gas accounts for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (SFAS No. 109) which requires that deferred tax assets and liabilities be recognized using enacted tax rates for the effect of temporary differences between the book and tax basis of recorded assets and liabilities. SFAS No. 109 also requires that deferred tax assets be reduced by a valuation allowance if it is more likely than not that some portion of the deferred tax asset will not be realized. At December 31, 2006, CNX Gas had deferred tax liabilities in excess of deferred tax assets of approximately $123,000. 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

Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143) requires that the fair value of an asset retirement obligation be recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The 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 proved reserves, assumptions involving profit margins, inflation rates, and the assumed credit-adjusted risk-free interest rate.

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

Liquidity and Capital Resources

We intend to satisfy our future working capital requirements and fund our capital expenditures with cash from operations and our $200,000 credit facility. Our credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. We may use borrowings under the credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. Our obligations under our credit agreement are not secured by a lien on our assets.

As a result of our status as a majority-owned subsidiary of CONSOL Energy and having entered into a credit agreement with third party commercial lenders, CNX Gas and its subsidiaries are guarantors of CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000, which require all subsidiaries of CONSOL Energy that incur third party debt to also guarantee the 7.875% notes. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture governing the 7.875% notes and the agreement governing CONSOL Energy’s 8.25% medium term notes due June 1, 2007 require CNX Gas to ratably secure both the 7.875% notes and the medium term notes.

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

We have also entered into various gas swap transactions that qualify as financial cash flow hedges, which exist parallel to the underlying physical transactions. The fair value of these contracts was a net asset of $4,083 at December 31, 2006. The ineffective portion of the changes in the fair value of these contracts was immaterial for the twelve months ended December 31, 2006.

Cash Flows


	2006			2005
	Year to			Year to
	Date			Date			Change
Cash provided by operating activities	$	243,569		$	144,997		$	98,572
Cash used in investing activities	$	(156,020	)	$	(108,287	)	$	(47,733	)
Cash used in financing activities	$	(449	)	$	(16,640	)	$	16,191

After the separation from CONSOL Energy in August 2005, the receivables and subsequent cash receipts we generate from sales now remain with CNX Gas, which have increased the cash provided by operations in the current year. These were previously treated as a component of financing costs in the prior year. The increase in cash used in investing activities is the result of our expanded capital budget program designed to increase production and develop our acreage positions.

Contractual Commitments

The following is a summary of our significant contractual obligations at December 31, 2006 (in thousands). We estimate payments related to these items, net of any applicable reimbursements, at December 31, 2006 to be as follows:


	Within		1-3		3-5		More than
(In thousands)	1 Year		Years		Years		5 Years		Total
Long Term Debt Obligations	$	—	$	—	$	—	$	—	$	—
Capital Lease Obligations		2,573		5,751		6,660		51,486		66,470
Operating Lease Obligations		794		1,393		1,137		299		3,623
Gas Firm Transportation Obligations		7,897		14,642		12,430		21,453		56,422
Other Long-Term Liabilities:
Other Liabilities ^(a)		—		—		—		13,862		13,862
Well Plugging Liabilities		401		801		801		7,211		9,214
Pension		3		14		23		149		189
Postretirement Benefits Other than Pension		12		68		154		2,091		2,325

Total Contractual Obligations	$	11,680	$	22,669	$	21,205	$	96,551	$	152,105


(a)		This item represents legal contingencies reflected on the balance sheet for potential settlements of the two cases referenced in Note 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 Annual Report, our determination of these long-term liabilities is calculated annually and is based on several assumptions, including then prevailing conditions, which may change from year to year. In any year, if our assumptions are inaccurate, we could be required to expend greater amounts than anticipated.

$200,000 Credit Facility.

As described above, we and our wholly-owned subsidiaries are party to a credit agreement dated as of October 7, 2005 with a group of commercial lenders. This credit agreement provides for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. We may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. At December 31, 2006, CNX Gas does not have any outstanding debt, however our borrowing base is reduced by $16,867 related to outstanding letters of credit.

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

Off-Balance Sheet Arrangements

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

Recent Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, however earlier application is permitted provided the reporting entity has not yet issued financial statements for that fiscal year. We do not expect that this guidance will have a significant impact on CNX Gas.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. SFAS 158 was issued to address concerns that prior standards on employers’ accounting for defined benefit postretirement plans failed to communicate the funded status of those plans in a complete and understandable way and to require an employer to recognize completely in earnings or other comprehensive income the financial impact of certain events affecting the plan’s funded status when those events occurred. This Statement is effective for financial statements issued for fiscal years ending after December 15, 2006. Retrospective application of this Statement is not permitted. The overall actuarially estimated financial impact of this Statement increased accumulated other comprehensive income by $761, decreased long term liabilities by $1,246, and decreased deferred tax assets by $485 as of December 31, 2006. Additionally, SFAS 158 contains another provision which requires an employer to measure the funded status of each of its plans as of the date of its year-end statement of financial position. This provision becomes effective for CNX Gas for its December 31, 2008 year-end. The funded status of CNX Gas’ pension and other postretirement benefit plans are currently measured as of September 30.

In September 2006, the FASB issued Financial Accounting Standards Board Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1), which amended certain provisions in the American Institute of Certified Public Accountants (AICPA) Industry Audit Guide, Audits of Airlines (Airline Guide), and Accounting Principals Board Opinion No. 28: Interim Financial Reporting. The Board rescinded the accrue-in-advance method of accounting for planned major maintenance activities as it results in the recognition of liabilities that do not meet the definition of a liability in FASB Concepts Statement No. 6, Elements of Financial Statements, because it causes the recognition of a liability in a period prior to the occurrence of the transaction or event obligating the entity. The guidance in FSP AUG AIR-1 shall be applied to the first fiscal year beginning after December 15, 2006. Earlier adoption is permitted as of the beginning of an entity’s fiscal year. The guidance in FSP AUG AIR-1 shall be applied retrospectively for all financial statements presented, unless it is impracticable to do so. We do not expect this guidance to have a significant annual financial impact on CNX Gas.

In September 2006, the Securities and Exchange Commission issued Staff Accounting Bulletin No. 108 (SAB 108). SAB 108 was issued to provide interpretive guidance on how the effects of the carryover reversal of prior year misstatements should be considered in quantifying a current year misstatement. The provisions of SAB 108 are effective for CNX Gas for its December 31, 2006 year-end. The adoption of SAB 108 had no impact on CNX Gas’ consolidated financial statements.

In July 2006, the Financial Accounting Standards Board (FASB) released FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement 109” (FIN 48). FIN 48 provides a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that it has taken or expects to take on a tax return. We are in the process of evaluating the financial impact of adopting FIN 48, which will be effective for CNX Gas beginning in 2007, but do not expect any significant impact.

In September 2005, the Financial Accounting Standards Board ratified the consensus reached by the Emerging Issues Task Force (“EITF”) on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The issue defines when a purchase and a sale of inventory with the same party that operates in the same line of business is recorded at fair value or considered a single non-monetary transaction subject to the fair value exception of APB Opinion No. 29. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process, or finished goods. In general, two or more transactions with the same party are treated as one if they are entered into in contemplation of each other. The rules apply to new arrangements entered into in reporting periods beginning after March 15, 2006. The accounting for transactions that CNX Gas considers matching buy/sell transactions were affected by this consensus and therefore, in the first quarter of 2006 these transactions were recorded on a net basis.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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

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

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

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

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

Sensitivity analyses of the incremental effects on pre-tax income for the twelve months ended December 31, 2006 of a hypothetical 10% and 25% change in natural gas prices for open derivative instruments as of December 31, 2006 are provided in the following table:


	Incremental Decrease Assuming a
	Hypothetical Price Increase of:
	10%		25%
	(In millions)
Pre-Tax Income ⁽¹⁾	$	8.1	$	31.0


(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 2007 through 2008 anticipated sales of natural gas to fixed prices. The sensitivity analyses reflect an inverse relationship between increases in commodity prices and a benefit to earnings. When commodity prices increase, pretax income decreases. As of December 31, 2006, the fair value of these contracts was a net gain of $2,491 (net of $1,592 deferred tax). We will continually evaluate the portfolio of derivative commodity instruments and adjust the strategy to anticipated market conditions and risks accordingly.

Hedging Volumes

As of December 31, 2006, our hedged volumes for the periods indicated are as follows:


	Three Months		Three Months		Three Months		Three Months
	Ended		Ended		Ended		Ended
	March 31,		June 30,		September 30,		December 31,		Total Year
2007 Fixed Price Volumes
Hedged Mcf		3,197,970		3,223,503		3,274,035		3,274,035		12,969,543
Weighted Average Hedge Price/Mcf	$	7.89	$	7.89	$	7.89	$	7.89	$	7.89
2008 Fixed Price Volumes
Hedged Mcf		1,847,716		1,847,716		1,868,020		1,868,020		7,431,472
Weighted Average Hedge Price/Mcf	$	7.20	$	7.20	$	7.20	$	7.20	$	7.20

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

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

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA


	Page
Financial Statements
Report of Independent Registered Public Accounting Firm		54
Consolidated Statements of Income for the twelve months ended December 31, 2006, 2005 and 2004		56
Consolidated Balance Sheets as of December 31, 2006 and 2005		57
Consolidated Statements of Stockholders’ Equity for the twelve months ended December 31, 2006, 2005 and 2004		58
Consolidated Statements of Cash Flows for the twelve months ended December 31, 2006, 2005 and 2004		59
Notes to Audited Financial Statements		60

Report of Independent Registered Public Accounting Firm

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

We have completed an integrated audit of CNX Gas Corporation’s 2006 consolidated financial statements and of its internal control over financial reporting as of December 31, 2006 and audits of its 2005 and 2004 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of CNX Gas Corporation and its subsidiaries (“CNX Gas”) at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006 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 of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 1 to the consolidated financial statements, CNX Gas changed the manner in which it accounts for stock-based compensation; defined benefit pension, other postretirement benefit plans and other employee benefits; and purchases and sales of gas with the same counterparty in 2006.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A., that CNX Gas maintained effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, CNX Gas maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control — Integrated Framework issued by the COSO. CNX Gas’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of CNX Gas’ internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)


	For the Twelve Months Ended December 31,
	2006		2005		2004
Revenue and Other Income:
Outside Sales	$	385,056	$	277,031	$	214,721
Related Party Sales		8,490		6,052		22,036
Royalty Interest Gas Sales		51,054		45,351		41,858
Purchased Gas Sales		43,973		275,148		112,005
Other Income		25,286		9,859		6,916

Total Revenue and Other Income		513,859		613,441		397,536

Costs and Expenses:
Lifting Costs		31,096		26,794		23,939
Gathering and Compression Costs		55,091		40,623		37,021
Royalty Interest Gas Costs		41,998		36,641		32,914
Purchased Gas Costs		44,843		278,720		113,063
Other		6,868		9,721		9,494
General and Administrative		38,654		19,171		15,530
Depreciation, Depletion and Amortization		37,999		35,039		32,889
Interest Expense		870		14		—

Total Costs and Expenses		257,419		446,723		264,850

Earnings Before Income Taxes		256,440		166,718		132,686
Income Taxes		96,573		64,550		51,898

Net Income	$	159,867	$	102,168	$	80,788

Earnings per share:
Basic	$	1.06	$	0.76	$	0.66

Diluted	$	1.06	$	0.76	$	0.66

Weighted Average Number of Common Shares Outstanding:
Basic		150,845,518		134,071,334		122,896,667

Dilutive		151,017,456		134,137,219		122,988,359

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

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)


	December 31,
	2006		2005
ASSETS
Current Assets:
Cash and Cash Equivalents	$	107,173	$	20,073
Accounts Receivable:
Trade		46,062		41,121
Net Related Party		2,745		728
Other		2,291		550
Deferred Taxes		—		9,339
Derivatives		10,548		—
Other Current Assets		3,917		2,378

Total Current Assets		172,736		74,189
Property, Plant and Equipment, Net		918,162		723,547
Other Assets		11,820		11,903
Investments in Equity Affiliates		52,283		49,528

TOTAL ASSETS	$	1,155,001	$	859,167

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities:
Accounts Payable	$	27,872	$	22,541
Accrued Royalties Payable		11,960		10,504
Accrued Severance Taxes		2,576		2,747
Accrued Income Taxes		2,191		5,518
Deferred Taxes		3,091		—
Derivatives		—		23,777
Other Current Liabilities		9,222		5,382

Total Current Liabilities		56,912		70,469
Deferred Taxes		120,008		47,736
Capital Lease Obligation		63,897		—
Other Liabilities		15,977		14,310
Well Plugging Liabilities		9,214		10,908
Derivatives		6,465		32,909
Postretirement Benefits Other Than Pension		2,313		3,363

Total Liabilities		274,786		179,695
Stockholders’ Equity
Common Stock, $.01 par value; 200,000,000 Shares Authorized, 150,864,075 Issued and Outstanding at December 31, 2006 and 150,833,334 Issued and Outstanding at December 31, 2005		1,508		1,508
Capital in Excess of Par Value		781,960		779,509
Retained Earnings (Deficit)		94,337		(65,530	)
Accumulated Other Comprehensive Income (Loss)		2,410		(34,733	)
Unearned Compensation on Restricted Stock Units		—		(1,282	)

Total Stockholders’ Equity		880,215		679,472

TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	1,155,001	$	859,167

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

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Dollars in thousands)


									Accumulated			Unearned
			Capital In			Retained			Other			Compensation			Total
	Common		Excess of			Earnings			Comprehensive			on Restricted			Stockholders’
	Stock		Par Value			(Deficit)			Income (Loss)			Stock Units			Equity
Balance at December 31, 2003	$	—	$	297,947		$	171,681		$	(5,396	)	$	—		$	464,232
Net Income		—		—			80,788			—			—			80,788
Gas Cash Flow Hedge (Net of $146 tax)		—		—			—			(227	)^(a)		—			(227	)

Comprehensive Income (Loss)		—		—			80,788			(227	)		—			80,561
Return of Capital to Parent		—		(82,237	)		—			—			—			(82,237	)

Balance at December 31, 2004		—		215,710			252,469			(5,623	)		—			462,556
Net Income		—		—			102,168			—			—			102,168
Gas Cash Flow Hedge (Net of $18,542 tax)		—		—			—			(29,110	)^(b)		—			(29,110	)

Comprehensive Income (Loss)		—		—			102,168			(29,110	)		—			73,058
Issuance of Common Stock		1,508		418,659			—			—			—			420,167
Effect of Tax Basis Step-up		—		165,042			—			—			—			165,042
Issuance of Restricted Stock units under the Equity Incentive Plan (92,969 units)		—		1,487			—			—			(1,487	)		—
Stock-Based Compensation		—		—			—			—			205			205
Dividends paid		—		—			(420,167	)		—			—			(420,167	)
Return of Capital to Parent		—		(21,389	)		—			—			—			(21,389	)

Balance at December 31, 2005		1,508		779,509			(65,530	)		(34,733	)		(1,282	)		679,472
Net Income		—		—			159,867			—			—			159,867
Gas Cash Flow Hedge (Net of $23,859 tax)		—		—			—			36,382	^(c)		—			36,382

Comprehensive Income		—		—			159,867			36,382			—			196,249
Initial adjustment upon adoption of FAS 158 (net of $485 tax)		—		—			—			761			—			761
Elimination of Unearned Compensation on Restricted Stock Units		—		(1,282	)		—			—			1,282			—
Stock-Based Compensation		—		3,733			—			—			—			3,733

Balance at December 31, 2006	$	1,508	$	781,960		$	94,337		$	2,410	^(d)	$	—		$	880,215


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

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

(c)		Of the $36,382 net change in accumulated other comprehensive income (loss) in the period, $18,148 represents the settlements recognized in net income.

(d)		Comprised of unrealized transition adjustments of $592 OPEB revaluation and $169 Pension revaluation. Also, $1,649 of deferred net gains on financial instruments.

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

CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)


	For the Twelve Months
	Ended December 31,
	2006			2005			2004
Operating Activities:
Net Income	$	159,867		$	102,168		$	80,788
Adjustments to Reconcile Net Income to Net Cash Provided By Operating Activities:
Depreciation, Depletion and Amortization		37,999			35,039			32,889
Compensation from Restricted Stock Unit Grants		529			205			—
Compensation from Stock Option Grants		3,204			—			—
Deferred Income Taxes		60,358			46,779			50,957
Equity in (Income) Loss of Affiliates		(978	)		149			2,423
Changes in Operating Assets:
Accounts Receivable		(6,682	)		(40,236	)		(783	)
Related Party Receivable		(2,017	)		(728	)		—
Other Current Assets		(2,284	)		3,542			(2,111	)
Changes in Other Assets		83			(4,951	)		(2,367	)
Changes in Operating Liabilities:
Accounts Payable		(7,343	)		(8,936	)		2,597
Income Taxes		(3,327	)		5,650			941
Other Current Liabilities		2,552			14,861			4,241
Changes in Other Liabilities		1,668			(8,600	)		5,583
Other		(60	)		55			192

Net Cash Provided by Operating Activities		243,569			144,997			175,350

Investing Activities:
Capital Expenditures		(154,243	)		(110,752	)		(89,753	)
Investment in Equity Affiliates		(1,777	)		2,465			(3,361	)

Net Cash Used in Investing Activities		(156,020	)		(108,287	)		(93,114	)

Financing Activities:
Capital Lease Payments		(449	)		—			—
Issuance of Common Stock		—			420,167			—
Dividends Paid		—			(420,167	)		—
Payments to Parent		—			(16,640	)		(82,237	)

Net Cash Used in Financing Activities		(449	)		(16,640	)		(82,237	)

Net Increase (Decrease) in Cash and Cash Equivalents		87,100			20,070			(1	)
Cash and Cash Equivalents at Beginning of Year		20,073			3			4

Cash and Cash Equivalents at Year End	$	107,173		$	20,073		$	3

The accompanying notes are an integral part of these consolidated financial statements.
See Note 12 – Supplemental Cash Flow Information

CNX GAS CORPORATION AND SUBSIDIARIES

NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands)

Note 1—Significant Accounting Policies:

Nature of Operations

CNX Gas Corporation (CNX Gas) is a natural gas producer with an emphasis on Appalachian area natural gas drilling, gathering and sales. CNX Gas is one of the largest U.S. producers of Coal Bed Methane (CBM), and is one of the largest owners of proved gas reserves in the Appalachian Basin. CNX Gas gathers gas from wells it operates, and those operated by others, to interstate pipelines by way of the Cardinal States Gathering Company (CSGC) pipeline, the Jewell Ridge lateral pipeline and the Coalfield Pipeline Company pipeline. CNX Gas finances drilling activities through existing operations.

As of December 31, 2004, CNX Gas was not a legal entity and there were no outstanding shares of common stock. However, carved out financial statements were prepared in accordance with Regulation S-X Article 3 “General instructions as to financial statements” and SAB Topic 1-B1 “Costs reflected in historical financial statements” and are presented for comparative purposes. Shares of CNX Gas common stock were not issued until 2005. As of January 19, 2006, CNX Gas became a publicly traded company (trading under the symbol CXG on the NYSE) operating in the energy sector.

Basis of Consolidation

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

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


	CNX Gas %
Investee	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 plugging liabilities, proved gas reserves, income taxes, employee benefit related obligations and stock based compensation.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand and in financial institutions as well as all highly liquid short-term securities with original maturities of three months or less. As indicated on the cash flow statement, all cash transactions prior to separation from CONSOL Energy were considered either capital contributions or return of capital.

Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. CNX Gas reserves for specific accounts receivable when it is probable that all or a part of an outstanding balance will not be collected. CNX Gas regularly reviews collectibility and establishes or adjusts the allowance as necessary using the specific identification method. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. There were no reserves for uncollectible amounts in the periods presented.

Property, Plant and Equipment

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

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

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

Impairment of Long-Lived Assets

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

Gas Well Plugging Costs

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

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

Revenue Recognition

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

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

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

CNX Gas sells gas to accommodate the delivery points of its customers. In general, this gas is purchased at market price and re-sold on the same day at market price less a small transaction fee. CNX Gas also provides gathering services to third parties by way of matching buy/sell transactions. These revenues and expenses are recorded gross in the statement of operations and recognized immediately in earnings.

Royalty Recognition

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

Contingencies

CNX Gas and our subsidiaries from time to time are subject to various lawsuits and claims with respect to such matters as personal injury, wrongful death, damage to property, exposure to hazardous substances, governmental regulations including environmental remediation, employment and contract disputes, and other claims and actions, arising out of the normal course of business. Liabilities are recorded when it is probable that obligations have been incurred and the amounts can be reasonably estimated. Estimates are developed through consultation with legal counsel involved in the defense and are based upon an analysis of potential results, assuming a combination of litigation and settlement strategies. Environmental liabilities are not discounted or reduced by possible recoveries from third parties.

Derivative Instruments

Stock-Based Compensation

Earnings Per Share

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

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

Basic earnings per share are computed by dividing net income by the weighted average shares outstanding during the twelve months ended December 31, 2006, 2005 and 2004. However, because CNX Gas was formed as a subsidiary of CONSOL Energy, the number of shares issued following formation is utilized for the 2004 period presented. Diluted earnings per share are computed similarly to basic earnings per share except that the weighted average shares outstanding are increased to include additional shares from the assumed exercise of stock options, if dilutive, and the assumed redemption of restricted stock units. The number of additional shares is calculated by assuming the outstanding stock options were exercised and the restricted stock units were converted into shares and the proceeds from such activity were used to acquire shares of common stock at the average market price during the reporting period. There were no anti-dilutive shares at December 31, 2006.


	For the Twelve Months
	Ended December 31,
	2006		2005		2004
Net Income	$	159,867	$	102,168	$	80,788

Weighted Average Number of Common Shares Outstanding:
Basic		150,845,518		134,071,334		122,896,667
Effect of stock options		171,938		65,885		91,692

Dilutive		151,017,456		134,137,219		122,988,359

Earnings per share:
Basic	$	1.06	$	0.76	$	0.66

Diluted	$	1.06	$	0.76	$	0.66

Recent Accounting Pronouncements

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 157, “Fair Value Measurements” (SFAS 157), which defines fair value, establishes a framework for measuring fair value in accordance with accounting principles generally accepted in the United States of America, and requires additional disclosures about fair value measurements. SFAS 157 aims to improve the consistency and comparability of fair value measurements by creating a single definition of fair value. The Statement emphasizes that fair value is not entity-specific, but instead is a market-based measurement of an asset or liability. SFAS 157 upholds the requirements of previously issued pronouncements concerning fair value measurements and expands the required disclosures. This Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, however earlier application is permitted provided the reporting entity has not yet issued financial statements for that fiscal year. We do not expect that this guidance will have a significant impact on CNX Gas.

In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. SFAS 158 was issued to address concerns that prior standards on employers’ accounting for defined benefit postretirement plans failed to communicate the funded status of those plans in a complete and understandable way and to require an employer to recognize completely in earnings or other comprehensive income the financial impact of certain events affecting the plan’s funded status when those events occurred. This Statement was adopted by CNX Gas on December 31, 2006 as indicated on Note 10. The overall actuarially estimated financial impact of this Statement increased accumulated other comprehensive income by $761, decreased long term liabilities by $1,246, and decreased deferred tax assets by $485 as of December 31, 2006. Additionally, SFAS 158 contains another provision which requires an employer to measure the funded status of each of its plans as of the date of its year-end statement of financial position. This provision becomes effective for CNX Gas for its December 31, 2008 year-end. The funded status of CNX Gas’ pension and other postretirement benefit plans are currently measured as of September 30.

In September 2006, the FASB issued Financial Accounting Standards Board Staff Position No. AUG AIR-1, “Accounting for Planned Major Maintenance Activities” (FSP AUG AIR-1), which amended certain provisions in the American Institute of Certified Public Accountants (AICPA) Industry Audit Guide, Audits of Airlines (Airline Guide), and Accounting Principals Board Opinion No. 28: Interim Financial Reporting. The Board rescinded the accrue-in-advance method of accounting for planned major maintenance activities as it results in the recognition of liabilities that do not meet the definition of a liability in FASB Concepts Statement No. 6, Elements of Financial Statements, because it causes the recognition of a liability in a period prior to the occurrence of the transaction or event obligating the entity. The guidance in FSP AUG AIR-1 shall be applied to the first fiscal year beginning after December 15, 2006. Earlier adoption is permitted as of the beginning of an entity’s fiscal year. The guidance in FSP AUG AIR-1 shall be applied retrospectively for all financial statements presented, unless it is impracticable to do so. We do not expect this guidance will have a significant annual financial impact on CNX Gas.

Reclassifications:

Certain amounts in prior periods have been reclassified to conform with the report classifications of the year ended December 31, 2006 with no effect on previously reported net income or stockholders’ equity. The reclassifications include the netting of firm transportation obligations previously recorded in current assets and current liabilities, reclassifications within property, plant and equipment, reclassifications between other costs and administrative costs, and the reporting of royalty interest gas sales and royalty interest gas costs

Note 2—Transactions with Related Parties:

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


	For the Twelve Months
	Ended December 31,
	2006		2005		2004
Sales of Gas-Related Party	$	8,490	$	6,052	$	22,036
Supply Purchases	$	210	$	135	$	137

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

General and administrative expenses contain fees of $3,954, $5,669, and $6,327 for the twelve months ended December 31, 2006, 2005, and 2004, respectively, for certain accounting and administrative services provided by CONSOL Energy. These fees are allocated to CNX Gas based on annual estimated hours worked on CNX Gas versus total hours available.

CNX Gas paid CONSOL Energy $37,241 and $12,233 for federal and state taxes related to income for the twelve months ended December 31, 2006 and 2005, respectively.

CONSOL Energy currently incurs drilling costs related to gob gas production due to the necessity to de-gas coal mines prior to production for safety reasons. The cost to CONSOL Energy for drilling these wells was as follows: $8,917 in 2006, $6,200 in 2005, and $9,100 in 2004. CNX Gas captures and markets the gas from these wells and, therefore, benefits from this drilling activity, although CNX Gas is not burdened with the cost to drill gob wells. CNX Gas is responsible for the costs incurred to gather and deliver the gob gas to market. All gob well drilling costs are borne by CONSOL Energy and only the collection and processing costs are recorded in CNX Gas’ financial statements. CNX Gas’ master cooperation and safety agreement with CONSOL Energy retained this cost structure after its separation from CONSOL Energy in August 2005.

CNX Gas employees may also participate in certain benefit programs administered by CONSOL Energy, which are discussed further in Note 10. Our allocation of pension expense was $526 up to the point of separation in 2005, and $1,433 for the twelve months ended December 31, 2004.

Employees may also participate in a defined contribution investment plan administered by CONSOL Energy. Amounts charged to expense by CNX Gas for the investment plan were $646, $442, and $337 for the twelve months ended December 31, 2006, 2005, and 2004, 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 $321, $228, and $140 for the twelve months ended December 31, 2006, 2005, and 2004, respectively. Allocation of the expense for this plan is based on the percentage of CNX Gas’ active salary employees compared to the total active salary employees covered by the plan.

CNX Gas also participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least twenty years of service and have attained age 55 or fifteen years of service and have attained age 62. Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of one thousand dollars per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include a cost sharing structure where essentially all participants contribute a minimum of 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants. CNX Gas does not expect to contribute to the other postretirement benefit plan in 2007 and instead expects to pay benefit claims as they become due.

CNX Gas is insured through CONSOL Energy for workers’ compensation claims in several states and is self-insured for these claims in Virginia. Workers’ compensation expense for these benefits was $16, $34, and $22 for the twelve months ended December 31, 2006, 2005, and 2004, respectively.

CONSOL Energy has provided financial guarantees on behalf of CNX Gas. As discussed in Note 15, CNX Gas anticipates that these parental guarantees will be transferred from CONSOL Energy to CNX Gas over time. We also believe that these parental guarantees will expire without being funded, and therefore will not have a material adverse effect on the financial statements.

CNX Gas is insured through CONSOL Energy’s business interruption insurance, and pays allocated premiums directly to CONSOL Energy. During the current year, CNX Gas received proceeds from this policy of $10,165 related to CONSOL Energy mine incidents in the prior year.

Note 3—Other Income:


	For the Twelve Months
	Ended December 31,
	2006		2005		2004
Other Royalty Income	$	10,230	$	8,158	$	5,726
Insurance Proceeds		10,165		—		—
Interest Income		3,453		418		—
Third Party Gathering Revenue		1,341		1,110		1,109
Miscellaneous		97		173		81

Total Other Income	$	25,286	$	9,859	$	6,916

Note 4—Income Taxes:

Income taxes provided on earnings consisted of:


	For the Twelve Months
	Ended December 31,
	2006		2005		2004
Current:
Federal	$	30,032	$	14,713	$	941
State		6,183		3,058		—
Deferred:
Federal		52,646		38,957		42,250
State		7,712		7,822		8,707

Total Income Tax Expense	$	96,573	$	64,550	$	51,898

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


	December 31,
	2006			2005
Deferred Tax Assets:
Capital Lease Obligations	$	25,896		$	—
Derivatives		—			22,266
Well Plugging		3,590			4,285
Other Postretirement Benefits		901			1,321
Stock-Based Compensation		1,455			—
Other		1,583			—

Total Deferred Tax Assets		33,425			27,872

Deferred Tax Liabilities:
Property, Plant and Equipment		(145,179	)		(58,588	)
Investment in Equity Affiliates		(8,501	)		(7,681	)
Derivatives		(1,906	)		—
Other		(938	)		—

Total Deferred Tax Liabilities		(156,524	)		(66,269	)

Net Deferred Tax Liabilities	$	(123,099	)	$	(38,397	)

CNX Gas has implemented the qualified production activities deduction as enacted by the American Jobs Creation Act of 2004. The deduction is currently equal to 3% of qualified production activities income as limited by taxable income and is also limited by 50 percent of the employer’s W-2 wages for the tax year. CNX Gas has estimated the deduction to be $2,762 for 2006.

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

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


	Twelve Months
	Ended December 31,
	2006						2005						2004
	Dollars			Rate			Dollars			Rate			Dollars			Rate
Statutory U.S. Federal Income Tax Rate	$	89,754			35.0	%	$	58,351			35.0	%	$	46,440			35.0	%
Net Effect of State Income Tax		9,032			3.5	%		7,072			4.2	%		5,659			4.3	%
Effect of Manufacturer’s Deduction		(967	)		(0.4	)%		(455	)		(0.3	)%		—			—	%
Other		(1,246	)		(0.4	)%		(418	)		(0.2	)%		(201	)		(0.2	)%

Income Tax Expense/ Effective Rate	$	96,573			37.7	%	$	64,550			38.7	%	$	51,898			39.1	%

Note 5—Gas Well Plugging Costs:

The reconciliation of changes in the asset retirement obligations at December 31, 2006 and 2005 is as follows:


	As of December 31,
	2006			2005
Balance at beginning of period	$	10,908		$	8,685
Accretion expense		517			660
Payments		(183	)		(1,086	)
Liabilities incurred		1,348			945
Revisions in estimated cash flows		(3,376	)		1,807
Other		—			(103	)

Balance at end of period	$	9,214		$	10,908

Note 6—Property, Plant and Equipment:


	As of December 31,
	2006			2005
Surface Lands	$	37,055		$	26,573
Mineral Interests		55,623			55,621
Wells and Related Equipment		112,009			83,633
Intangible Drilling		383,605			312,467
Gathering Assets		520,906			402,681
Gas Well Plugging		5,652			7,680
Capitalized Internal Software		6,433			36

Total Property, Plant and Equipment		1,121,283			888,691
Accumulated Depreciation, Depletion and Amortization		(203,121	)		(165,144	)

Property and Equipment, net	$	918,162		$	723,547

Property, plant and equipment includes gross assets acquired under capital leases of $66,919 at December 31, 2006 with related amounts in accumulated depreciation, depletion and amortization of $781 at December 31, 2006. There were no capital lease obligations at December 31, 2005.

Note 7—Credit Facility:

In 2005, CNX Gas entered into a credit agreement for a revolving credit facility in an initial aggregate outstanding principal amount of up to $200,000 (with the ability to request an increase in the aggregate outstanding principal amount up to $300,000), including borrowings and letters of credit. CNX Gas may use borrowings under the new credit agreement for general corporate purposes, including transaction fees, letters of credit, acquisitions, capital expenditures and working capital. The $200,000 credit agreement for CNX Gas is unsecured, however it does contain a negative pledge provision providing that CNX Gas assets cannot be used to secure any other obligations. Fees and interest rate spreads are based on the percentage of facility utilization, measured quarterly. Covenants in the facility limit our ability to dispose of assets, make investments, purchase or redeem CNX Gas stock and merge with another corporation. The facility includes a leverage ratio covenant of not more than 3.0 to 1.0, measured quarterly. As there was no debt outstanding at December 31, 2006, the leverage ratio was met at December 31, 2006. The facility also includes an interest coverage ratio of no less than 3.0 to 1.0 measured quarterly. The interest coverage ratio covenant was met, as interest expense was immaterial.

At December 31, 2006, the CNX Gas credit agreement had no borrowings outstanding and $16,867 of letters of credit outstanding, leaving $183,133 of capacity available for borrowings and the issuance of letters of credit.

As a result of entering into the $200,000 credit agreement, CNX Gas and subsidiaries have executed a Supplemental Indenture and are guarantors of CONSOL Energy’s 7.875% notes due March 1, 2012 in the principal amount of approximately $250,000. In addition, if CNX Gas were to grant liens to a lender as part of a future borrowing, the indenture and the agreement governing CONSOL Energy’s 8.25% medium term notes due 2007 in the principal amount of $45,000 would require CNX Gas to ratably secure both the 7.875% notes and the 8.25% medium term notes.

Note 8—Other Current Liabilities:


	As of December 31,
	2006		2005
Short Term Incentive Compensation Plan	$	3,944	$	2,755
Current Portion of Capital Lease		2,573		—
Accrued Payroll		1,582		1,781
Other		613		590
Gas Firm Transportation		510		256

Total Other Current Liabilities	$	9,222	$	5,382

Note 9—Leases:

CNX Gas uses various leased facilities and equipment in our operations, which qualify as operating leases. CNX Gas also recorded a pipeline transportation arrangement as a capital lease in 2006. Future minimum lease payments under these leases are as follows:


	Capital		Operating
	Leases		Leases
2007	$	7,380	$	794
2008		7,380		695
2009		7,380		698
2010		7,380		701
2011		7,380		436
Thereafter		72,461		299

Total Minimum Lease Payments	$	109,361	$	3,623

Less Imputed Interest		42,891
Present Value of Minimum Lease Payments	$	66,470

Less Amount Due in One Year		2,573

Total Long-term Capital Lease Obligation	$	63,897

Rental expense under operating leases was $3,495, $2,892, and $1,566 for the twelve months ended December 31, 2006, 2005, and 2004, respectively.

Note 10—Pension and Other Postretirement Benefits:

Changes In Accounting Standards

In the year ended December 31, 2006, CNX Gas adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (FAS 158), which requires the recognition of the funded status of defined benefit postretirement plans and related disclosures. While it does not impact net income, this resulted in a one-time adjustment to accumulated other comprehensive income in shareholders’ equity of $169 and $592 (net of tax) for the Pension Plan and other postretirement plans, respectively.

Defined Benefit Pension Plan

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

Effective January 1, 2007, employees hired by CNX Gas will not be eligible to participate in the non-contributory defined benefit retirement plan. In lieu of participation in the non-contributory defined benefit plan, these employees will begin receiving an additional 3% company contribution into their defined contribution plan. CNX Gas employees who were hired prior to December 31, 2005 or who were full time salaried employees of CONSOL Energy immediately prior to their date of transfer were given a one time opportunity to elect to remain in the defined benefit plan or to freeze their defined benefit accruals and participate in the additional 3% company contribution into their defined contribution plan. All employees, regardless of the hire date or plan election, will continue to receive up to a 6% company match of eligible pay contributed to the defined contribution plan. In addition, any employees hired on or after January 1, 2006 had their pension benefit frozen as of December 31, 2006 and are automatically enrolled into the additional 3% company contribution into their defined contribution effective January 1, 2007. The company intends to freeze all defined benefit accruals after ten years for employees that elected to remain in the defined benefit plan.

The CNX Gas Pension Plan uses a measurement period of October 1 through September 30 to determine components of net periodic pension expense. Census data is gathered annually as of January 1 and projected to September 30. The reconciliation of changes in the benefit obligation and funded status of this plan at December 31, 2006 and 2005 is as follows:


	As of December 31,
	2006			2005
Change in benefit obligation:
Benefit obligation at beginning of the year	$	88		$	—
Service cost		282			207
Interest cost		5			12
Actuarial gain		(164	)		(131	)
Benefits paid		(4	)		—

Benefit obligation at end of the year	$	207		$	88

Fair Value of Plan assets	$	18		$	—
Funded Status:
Status of plan underfunded	$	(189	)	$	(88	)
Unrecognized net actuarial gain		(276	)		(131	)

Accrued benefit cost before the adoption of SFAS 158	$	(465	)	$	(219	)

Amounts Recognized in the Consolidated Balance Sheets:
Accrued benefit liability	$	(465	)	$	(219	)

Net amount recognized	$	(465	)	$	(219	)

After the adoption of SFAS 158:
Noncurrent liabilities	$	(189	)	$	—

Net amount recognized	$	(189	)	$	—

Amounts recognized in accumulated other comprehensive income consist of:
Net Gain	$	(276	)	$	—

Net amount recognized (before tax effect)	$	(276	)	$	—


	Balance Prior to						Balance After
	SFAS 158			SFAS 158			SFAS 158
	Adjustments			Adjustments			Adjustments
Change due to the adoption of SFAS 158 at December 31, 2006:

Accrued pension benefit liability	$	(465	)	$	276		$	(189	)

Accumulated other comprehensive income (before tax effects of $107)	$	—		$	(276	)	$	(276	)

The accumulated benefit obligation for the Pension Plan at December 31, 2006 and 2005 was $160 and $74, respectively. We expect to recognize $23 of the net gain in earnings in 2007.

The components of net periodic benefit costs are as follows:


	For the Twelve Months
	Ended December 31,
	2006			2005
Components of Net Periodic Benefit Costs:
Service costs	$	282		$	219
Interest costs		5			—
Expected return on plan assets		(9	)		—
Recognized net actuarial gain		(12	)		—

Benefit costs	$	266		$	219

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


	As of December 31,
	2006			2005
Discount rate		6.00	%		5.75	%
Expected long-term return on plan assets		8.00	%		—
Rate of compensation increase		4.36	%		4.11	%

The company calculates net periodic pension cost for a given fiscal year based on the assumptions developed at the end of the previous fiscal year. The weighted-average assumptions used to determine net periodic benefit cost are as follows:


	As of December 31,
	2006			2005
Discount rate		5.75	%		6.00	%
Expected long-term return on plan assets		8.00	%		—
Rate of compensation increase		4.11	%		4.12	%

The Pension Plan had no plan assets as of December 31, 2005. CNX Gas contributed $20 during fiscal year 2006. The fair value of plan assets at December 31, 2006 was $18, all of which are in cash and cash equivalents.

We expect to contribute $282 to the Pension Plan in 2007. Benefit payments reflecting future service for the years 2007 through 2016 are expected to be approximately $254.

Postretirement Benefit Plans

CNX Gas also participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least twenty years of service and have attained age 55 or fifteen years of service and have attained age 62. Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of $1,000 per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include a cost sharing structure where essentially all participants contribute 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants. CNX Gas does not expect to contribute to the other postretirement benefit plan in 2007. CNX Gas expects to pay benefit claims as they become due. CNX Gas uses a September 30 measurement date for its other postretirement benefit plans.

The reconciliation of changes in the benefit obligation and funded status of these plans as of December 31, 2006 and 2005 is as follows:


	Other Benefits as of December 31,
	2006			2005
Change in benefit obligation:
Benefit obligation at beginning of period	$	1,760		$	2,826
Service cost		91			160
Interest cost		101			170
Actuarial gain (loss)		466			(765	)
Plan amendments		—			(631	)
Benefits paid		(93	)		—

Benefit obligation at end of period	$	2,325		$	1,760

Funded Status:
Status of plan underfunded	$	(2,325	)	$	(1,760	)
Unrecognized prior service cost		(1,459	)		(1,631	)
Unrecognized net actuarial loss		489			23

Accrued benefit cost before the adoption of SFAS 158	$	(3,295	)	$	(3,368	)

Amounts Recognized in the Consolidated Balance Sheets before the adoption of SFAS 158 consist of:
Accrued benefit liability		(3,295	)		(3,368	)

Net amount recognized	$	(3,295	)	$	(3,368	)

After the adoption of SFAS 158:
Current liabilities		(12	)		—
Noncurrent liabilities		(2,313	)		—

Net amount recognized	$	(2,325	)	$	—

Amounts recognized in accumulated other comprehensive income consist of:
Net Loss	$	489		$	—
Prior Service Cost		(1,459	)		—

Net amount recognized (before tax effect)	$	(970	)	$	—


	Balance Prior to						Balance After
	SFAS 158			SFAS 158			SFAS 158
	Adjustments			Adjustments			Adjustments
Change due to the adoption of SFAS 158 at December 31, 2006:
Accrued postretirement benefit liability	$	(3,295	)	$	970		$	(2,325	)
Accumulated other comprehensive income – postretirement benefits (before tax effects of $378)	$	—		$	(970	)	$	(970	)

We expect to recognize a gain of $172 related to prior service costs, and a loss of $20 related to the net actuarial loss in earnings in 2007.

The components of net periodic benefit costs are as follows:


	For the Twelve Months
	Ended December 31,
	2006			2005			2004
Components of Net Periodic Benefit Costs:
Service costs	$	91		$	160		$	131
Interest costs		101			170			163
Amortization of prior service costs credit		(172	)		(113	)		(117	)
Recognized net actuarial loss		—			42			63

Benefit costs	$	20		$	259		$	240

The company calculates net periodic benefit cost for a given fiscal year based on the assumptions developed at the end of the previous fiscal year. The weighted-average assumptions used to determine benefit obligations are as follows:


	As of December 31,
	2006			2005			2004
Discount rate		6.00	%		5.75	%		6.00	%

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


	As of December 31,
	2006			2005			2004
Discount rate		5.75	%		6.00	%		6.00	%

The assumed health care cost trend rates are as follows:


	December 31,
	2006			2005			2004
Healthcare cost trend rate for next year		8.50	%		9.25	%		10.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		5.00	%		4.75	%		4.75	%
Year that the rate reaches ultimate trend rate		2011			2011			2011

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		1-Percentage
	Point Increase		Point Decrease
Effect on total of service and interest costs components	$	34	$	(31	)
Effect on accumulated postretirement benefit obligation		344		(296	)

CNX Gas had no plan assets as of December 31, 2006 and December 31, 2005 for other postretirement benefits. The company intends to pay benefit claims as they are due. The following benefit payments reflecting future service are expected to be paid as follows:


	Other Benefits
	Payments
2007	$	12
2008		26
2009		42
2010		65
2011		89
Year 2012-2016		801

Note 11—Stock-Based Compensation:

CNX Gas adopted the CNX Gas Equity Incentive Plan on June 30, 2005, and amended the plan on August 1, 2005 and again on October 11, 2006. The August 1 amended plan was approved by the sole stockholder of CNX Gas, CONSOL Energy, on August 4, 2005. The October 11, 2006 amendment was approved by the Board. The plan is administered by our board of directors and the board of directors may delegate administration of the plan to a committee of the board of directors. Our directors and employees, and our affiliates’ (which include CONSOL Energy) directors and employees, are eligible to receive awards under the plan. Some of our employees including our executive officers and non-employee directors have participated in or have been eligible to participate in and, will continue to be eligible to participate in, CNX Gas’ Equity Incentive Plan.

The CNX Gas Equity Incentive Plan consists of the following components: stock options, stock appreciation rights, restricted stock units, performance awards, cash awards and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX Gas’ plan is 2,500,000.

The total stock-based compensation expense was $3,733 and $205 for the years ended December 31, 2006 and 2005, and the related deferred tax benefit totaled $1,455 and $81 respectively. Prior to January 1, 2006, CNX Gas accounted for stock-based compensation under the recognition and measurement provisions of Accounting Principles Board Opinion (APB) No. 25, “Accounting for Stock Issued to Employees,” as amended. Generally, no stock-based employee compensation cost for stock options is reflected in net income, as all options granted under the plans had an exercise price equal to the market value of the underlying common stock on the date of the grant.

Prior to January 1, 2006, CNX Gas provided pro forma disclosure amounts in accordance with Statement of Financial Accounting Standards No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure – an Amendment of SFAS No. 123” (SFAS 148), as if the SFAS 123 provisions for income statement recognition had been applied to its stock-based compensation. The pro forma table below reflects net earnings and basic and diluted earnings per share for the year ended December 31, 2005, had CNX Gas applied the fair value recognition provisions of SFAS 123:


	For the Twelve Months Ended
	December 31, 2005
Net Income as reported	$	102,168
Add: Stock-based compensation expense for restricted stock units		205
Deduct: Total stock-based compensation expense determined under Black-Scholes option pricing model and stock-based compensation expense for restricted stock units, net of tax		(423	)

Pro forma net income	$	101,950


Earnings per share:
Basic – as reported	$	0.76
Basic – pro forma	$	0.76
Diluted – as reported	$	0.76
Diluted – pro forma	$	0.76

Effective January 1, 2006, CNX Gas adopted the fair value recognition provisions of SFAS 123R using the modified prospective transition method, and therefore has not restated results for prior periods. Under this transition method, stock-based compensation expense for the year ended December 31, 2006 includes compensation expense for all stock-based compensation awards granted prior to, but not yet vested as of, January 1, 2006, based on the grant date fair value estimated in accordance with the original provisions of SFAS 123. CNX Gas recognizes compensation costs for shares expected to vest on a straight-line basis over the requisite service period of the award, which is generally the option vesting term.

As a result of adopting SFAS 123R, pretax income and net income for the year ended December 31, 2006 was $3,204 and $1,956 lower, respectively, than if we had continued to account for stock-based compensation under APB 25. The impact on basic earnings per share and diluted earnings per share for the year ended December 31, 2006 was $0.01 per share. Upon the adoption of SFAS 123R, tax benefits resulting from tax deductions in excess of the compensation cost recognized for those options will be classified as financing cash flows when CNX Gas options are exercised in the future. As of December 31, 2006, there were no options exercised.

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


	For the year ended			For the year ended
	December 31, 2006			December 31, 2005
Weighted Average Fair Value of Grants	$	9.83		$	5.34
Risk Free Interest Rate		4.65	%		4.28	%
Dividend Yield		—			—
Expected Volatility		32.39	%		36.54	%
Expected Forfeiture Rate		2.0	%		—
Expected Term	4.5 years			4.5 years

Option activity under the CNX Gas Equity Incentive Plan during the year ended December 31, 2006 was as follows:


						Weighted
						Average
				Weighted		Remaining
				Average		Contractual		Aggregate Intrinsic
				Exercise		Terms		Value
	Shares			Price		(in years)		(in thousands)
Outstanding at December 31, 2005		1,040,576		$	16.05
Granted		486,678		$	28.43
Exercised		—			—
Forfeited		(29,935	)	$	19.17

Outstanding at December 31, 2006		1,497,319		$	20.01		8.83	$	9,627


Vested and Expected to Vest at December 31, 2006		1,494,218		$	20.00		8.83	$	9,627


Exercisable at December 31, 2006		249,008		$	16.05		8.59	$	2,352

These stock options will terminate ten years after the date on which they were granted. There are 1,018,254 employee stock options that vest 25% per year, beginning one year after the grant date and 454,076 employee stock options that vest 100%, three years after the grant date. There are 24,989 non-employee director stock options outstanding at December 31, 2006. Non-employee director stock options vest 33% per year, beginning one year after the grant date. The vesting of the options will accelerate in the event of death, disability or retirement and may accelerate upon a change of control of CNX Gas.

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

As of December 31, 2006, $6,380 of total unrecognized compensation cost related to unvested options awards is expected to be recognized over a weighted-average period of 2.58 years.

Under the Equity Incentive Plan, CNX Gas granted certain employees and certain directors restricted stock unit awards. These awards entitle the holder to receive shares of common stock as the award vests. A total of 68,371 restricted stock units were outstanding at December 31, 2006. Compensation expense will be recognized over the vesting period of the units. The total fair value of restricted stock unit awards that vested during the year was $529. The following represents the unvested restricted stock units and corresponding fair value (based upon the closing share price) at the date of the grant:


				Weighted
				Average
	Number of			Grant Date Fair
	Shares			Value
Non-vested at December 31, 2005		92,969		$	16.00
Granted		6,143			28.50
Vested		(30,741	)		16.00

Non-vested at December 31, 2006		68,371		$	17.12

As of December 31, 2006, $925 of total unrecognized compensation cost related to unvested RSU awards is expected to be recognized over a weighted-average period of 2.17 years.

Prior to the adoption of SFAS 123R on January 1, 2006, CNX Gas followed the nominal vesting period approach under APB No. 25 for awards with retirement eligible provisions. Upon adoption of SFAS 123R, CNX Gas changed to the non-substantive vesting period approach for awards with retirement eligible provisions. If CNX Gas would have followed the non-substantive vesting period approach for awards with retirement eligible provisions, we would have disclosed approximately $959 of additional expense, net of tax, for stock options for the year ended December 31, 2005.

Effective October 11, 2006, CNX Gas adopted a long-term incentive program. This program allows for the award of performance share units (PSUs). A PSU represents a contingent right to receive a cash payment, determined by reference to the value of one share of the company’s common stock. The total number of units earned, if any, by a participant will be based on the company’s total stockholder return relative to the stockholder return of a pre-determined peer group of companies. The performance period is from October 11, 2006 to December 31, 2009. CNX Gas will recognize compensation costs on a straight-line basis over the requisite service period. The basis of the compensation costs will be re-valued quarterly. As of December 31, 2006, there are 249,933 PSUs issued with a fair value of approximately $10,015. CNX Gas recognized approximately $770 in compensation costs in the current year.

Note 12—Supplemental Cash Flow Information:


	For the Twelve Months
	Ended December 31,
	2006			2005			2004
Net Cash provided from operating activities included:
Interest paid	$	870		$	14		$	—
Income Taxes paid	$	37,241		$	12,233		$	—
Non-cash investing and financing activities:
Capital Lease Obligation
Change in Assets	$	(66,919	)	$	—		$	—
Change in Liabilities	$	(66,919	)	$	—		$	—
Tax basis step-up	$	—		$	(165,041	)	$	—
Assumed ownership of joint venture assets	$	—		$	(4,769	)	$	—
Purchase of Property, Plant and Equipment
Change in Assets	$	(12,674	)	$	—		$	—
Change in Liabilities	$	(12,674	)	$	—		$	—

Note 13—Concentration of Credit Risk:

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

During the twelve months ended December 31, 2006, 2005 and 2004, CNX Gas made sales to four, three, and three unrelated entities respectively, which individually comprised greater than 10% of total revenues.

Note 14—Derivative Instruments:

CNX Gas has entered into derivative financial instruments, for purposes other than trading, to convert the market prices related to these anticipated sales of natural gas to fixed prices. These instruments are designated as cash flow hedges and extend through 2008. The net fair values of the outstanding instruments are an asset of $4,083 and a liability of $56,686 at December 31, 2006 and 2005, respectively.

CNX Gas entered into cash flow hedges for natural gas in 2006, 2005 and 2004. Gains or losses related to these derivative instruments were recognized when the sale of the natural gas affected earnings. The ineffective portion of the changes in the fair value of these contracts was insignificant in 2006 and 2005. There was no ineffectiveness in 2004 related to this hedging strategy.

For these cash flow hedge strategies, the fair values of the derivatives are recorded on the balance sheet. The effective portions of the changes in fair values of the derivatives are recorded in accumulated other comprehensive income and loss and are reclassified to sales in the period in which earnings are impacted by the hedged items or in the period that the transaction no longer qualifies as a cash flow hedge. There were no transactions that ceased to qualify as a cash flow hedge in 2006, 2005, or 2004. CNX Gas’ consolidated balance sheet is reflected on a net asset/(liability) basis for each counterparty.

Assuming market prices remain constant with prices at December 31, 2006, $6,438 of the net $1,649 gain included in other comprehensive income is expected to be recognized in earnings over the next 12 months. The remaining net loss is expected to be recognized in 2008.

CNX Gas did not have any derivatives designated as fair value hedges in 2006, 2005, or 2004.

Note 15—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 October 2005, CDX Gas, LLC (CDX) alleged that certain of our vertical to horizontal CBM drilling methods infringe several patents which they own. CDX demanded that we enter into a business arrangement with CDX to use its patented technology. Alternatively, CDX informally demanded a royalty of nine to ten percent of the gross production from the wells we drill utilizing the technology allegedly covered by their patents. We believe that approximately 31 of our producing wells to date could be covered by their claim. We deny all of these allegations and we are vigorously contesting them. On November 14, 2005, we filed a complaint for declaratory judgment in the U.S. District Court for the Western District of Pennsylvania (C.A. No. 05-1574), seeking a judicial determination that we do not infringe any claim of any valid and enforceable CDX patent. CDX filed an answer and counterclaim denying our allegations of invalidity and alleging that we infringe certain claims of their patents. A hearing was held before a Court-appointed Special Master with regard to the scope of the asserted CDX patents and the Special Master’s report and recommendations was adopted by order of the Court on October 13, 2006. As a result of that order and subject to appellate review, certain of our wells may be found to infringe certain of the CDX claims of the patents in suit, if those patents are ultimately determined to be valid and enforceable. The report of CDX’s damages expert suggests that CDX will seek (i) reasonable royalty damages on production from allegedly infringing wells at a royalty rate of 10%, or $1.9 million, based on projected production through June 2007, and (ii) “lost profits” damages of $23.6 million for allegedly infringing wells drilled though August 2006, which assumes that CNX Gas would have no choice but to have entered into a joint operating arrangement with CDX. We believe that there is no basis in the law for this “lost profits” theory. We continue to believe that we do not infringe any properly construed claim of any valid, enforceable patent. We cannot predict the ultimate outcome of this lawsuit; however, CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations or cash flows.

In 1999, CNX Gas was named in a suit brought by a group of royalty owners that lease gas development rights to CNX Gas in southwest Virginia. The suit alleged the underpayment of royalties to the group of royalty owners. The claim of underpayment of royalties related to the interpretation of permissible deductions from production revenues upon which royalties are calculated. The deductions at issue relate to post production expenses of gathering, compression and transportation. CNX Gas was ordered to, and subsequently paid in 2003, approximately $12,000 (including interest) to the group of royalty owners that brought the suit for the period from 1989 to 1999. A final payment was made to the plaintiffs in 2003 for approximately $5,600 to adjust all royalties owed to the plaintiffs from the date of the court ruling in 1999 forward to 2003, which effectively settled this case. CNX Gas has also recognized an estimated liability for other similar plaintiffs yet to be determined outside of this lawsuit. This amount is included in other liabilities on the balance sheet. To date, approximately $3,900 has been paid to various other royalty owners as a result of this case. CNX Gas management believes that the final resolution of this matter will not have a material effect on our financial position, results of operations or cash flows.

At December 31, 2006, CNX Gas has provided the following financial guarantees and letters of credit to certain third parties. CNX Gas management believes that these guarantees will expire without being funded, and therefore the commitments will not have a material adverse effect on financial condition. The fair value of all liabilities associated with these guarantees have been properly recorded and reported in the financial statements.


	Amounts		Less than						Beyond
Letters of Credit	Committed		1 Year		1-3 Years		3-5 Years		5 Years

Gas	$	16,867	$	16,847	$	20	$	0	$	0


Total Letters of Credit	$	16,867	$	16,847	$	20	$	0	$	0

Surety Bonds:
Environmental	$	278	$	278	$	0	$	0	$	0
Other		802		802		0		0		0


Total Surety Bonds	$	1,080	$	1,080	$	0	$	0	$	0

Other:
Firm Transportation	$	56,422	$	7,897	$	14,642	$	12,430	$	21,453
Guarantees	$	10,600	$	10,600		0		0		0


Total Other	$	67,022	$	18,497	$	14,642	$	12,430	$	21,453


Total Commitments	$	84,969	$	36,424	$	14,662	$	12,430	$	21,453

Letters of Credit

On December 28, 2006, CNX Gas obtained the issuance of a letter of credit to the Commonwealth of Pennsylvania in the amount of $20 to serve as collateral for a one year period for a permit issued by PENNDOT.

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

CNX Gas obtained the issuance of a letter of credit to East Tennessee Natural Gas, LLC to serve as collateral for a fifteen year firm transportation contract for approximately 197,500 Mcf per day on the Jewell Ridge Pipeline, which had an in-service date of October 2006. The amount of the letter of credit at December 31, 2006 is $15,695.

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

Surety Bonds

CNX Gas has issued surety bonds totaling $1,080. CNX Gas guarantees the performance of these obligations.

Other Guarantees

CNX Gas is the guarantor of an agreement with Saltville Gas Storage Company LLC for $3,600 dated October 26, 2006, an agreement with Constellation Energy Commodities Group, Inc. for $1,000 dated October 9, 2006, and an agreement with AEP for $6,000 dated July 31, 2006.

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

Note 16—Segment Information:

The principal activity of CNX Gas is to produce methane gas for sale primarily to gas wholesalers. CNX Gas has two reportable segments: Central Appalachia and Northern Appalachia. During the fourth quarter, management adjusted the manner in which results were internally reported to the Chief Operating Decision Maker. As a result of this change, the current period and all prior periods presented have been restated to reflect the way CNX Gas manages its operations and makes business decisions.

Reportable segment results for the twelve months ended December 31, 2006 are:


	Central		Northern						Adjustments &
	Appalachia		Appalachia		Total		Corporate		Eliminations			Consolidated
Sales—outside	$	364,025	$	21,031	$	385,056	$	—	$	—		$	385,056
Sales—related parties		8,392		98		8,490		—		—			8,490
Sales – royalty interest gas		50,878		176		51,054		—		—			51,054
Sales – purchased gas		43,973		—		43,973		—		—			43,973
Other revenue		21,048		785		21,833		3,453		—			25,286
Intersegment revenues		67,326		1,452		68,778		—		(68,778	)		—

Total Sales and Freight	$	555,642	$	23,542	$	579,184	$	3,453	$	68,778	)	$	513,859

Earnings Before Income Taxes ^(A)	$	250,607	$	3,825	$	254,432	$	2,008	$	—		$	256,440

Segment assets ^{(B) (C)}	$	949,472	$	73,596	$	1,023,068	$	131,933	$	—		$	1,155,001

Depreciation, depletion and amortization	$	35,190	$	2,809	$	37,999	$	—	$	—		$	37,999

Capital expenditures	$	122,287	$	31,956	$	154,243	$	—	$	—		$	154,243


(A)		Includes equity in earnings (loss) of unconsolidated affiliates of $1,405 and ($427) for Central Appalachia and Corporate segments, respectively.

(B)		Includes investments in unconsolidated equity affiliates of $27,523 and $24,760 for Central Appalachia and Corporate segments, respectively.

(C)		Includes cash of $107,173 in the Corporate segment.

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


	Central		Northern							Adjustments &
	Appalachia		Appalachia		Total		Corporate			Eliminations			Consolidated
Sales—outside	$	256,967	$	20,064	$	277,031	$	—		$	—		$	277,031
Sales—related parties		5,969		83		6,052		—			—			6,052
Sales – royalty interest gas		45,128		223		45,351		—			—			45,351
Sales—purchased gas		275,148		—		275,148		—			—			275,148
Other revenue		9,620		54		9,674		185			—			9,859
Intersegment revenues		46,680		795		47,475		—			(47,475	)		—

Total Sales and Freight	$	639,512	$	21,219	$	660,731	$	185		$	(47,475	)	$	613,441

Earnings (Loss) Before Income Taxes ^(D)	$	162,769	$	4,339	$	167,108	$	(390	)	$	—		$	166,718

Segment assets ^{(E) (F)}	$	763,432	$	41,135	$	804,567	$	54,600		$	—		$	859,167

Depreciation, depletion and amortization	$	31,619	$	3,420	$	35,039	$	—		$	—		$	35,039

Capital expenditures	$	87,508	$	23,244	$	110,752	$	—		$	—		$	110,752


(D)		Includes equity in earnings (loss) of unconsolidated affiliates of $138 and ($287) for Central Appalachia and Corporate segments, respectively.

(E)		Includes investments in unconsolidated equity affiliates of $24,340 and $25,188 for Central Appalachia and Corporate segments, respectively.

(F)		Includes cash of $20,073 in the Corporate segment

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


	Central		Northern						Adjustments &
	Appalachia		Appalachia		Total		Corporate		Eliminations			Consolidated
Sales—outside	$	206,670	$	8,051	$	214,721	$	—	$	—		$	214,721
Sales—related parties		22,000		36		22,036		—		—			22,036
Sales – royalty interest gas		41,843		15		41,858		—		—			41,858
Sales—purchased gas		112,005		—		112,005		—		—			112,005
Other revenue		6,738		58		6,796		120		—			6,916
Intersegment revenues		48,523		177		48,700		—		(48,700	)		—

Total Revenue and Other Income	$	437,779	$	8,337	$	446,116	$	120	$	(48,700	)	$	397,536

Earnings Before Income Taxes ^(G)	$	131,682	$	884	$	132,566	$	120	$	—		$	132,686

Segment assets ^(H)	$	663,116	$	21,794	$	684,910	$	33,949	$	—		$	718,859

Depreciation, depletion and amortization	$	32,198	$	691	$	32,889	$	—	$	—		$	32,889

Capital expenditures	$	82,990	$	6,763	$	89,753	$	—	$	—		$	89,753


(G)		Includes equity in loss of unconsolidated affiliates of $1,508 and $915 for Central Appalachia and Corporate segments, respectively.

(H)		Includes investments in unconsolidated equity affiliates of $21,728 and $25,645 for Central Appalachia and Corporate segments, respectively.


	For the Twelve Months Ended December 31,
	2006				2005				2004
	Consolidated		Equity		Consolidated		Equity		Consolidated		Equity
	Operations		Affiliates		Operations		Affiliates		Operations		Affiliates
Property acquisitions	$	9,562	$	—	$	8,333	$	20	$	4,190	$	111
Development		151,774		—		86,273		—		77,478		—
Exploration		832		2,334		19,370		412		5,596		2,902

Total	$	162,168	$	2,334	$	113,976	$	432	$	87,264	$	3,013


(*)		Includes costs incurred whether capitalized or expensed

At least 92%, of our acquisition costs are related to proved properties.

Results of Operations:


	For the Twelve Months Ended December 31,
	2006						2005						2004
	Consolidated			Equity			Consolidated			Equity			Consolidated			Equity
	Operations			Affiliates			Operations			Affiliates			Operations			Affiliates
Production Revenue	$	393,649		$	1,913		$	283,137		$	2,406		$	236,811		$	1,341
Royalty Interest Gas Revenue		51,054			446			45,351			408			41,858			246
Purchased Gas Revenue		43,973			356			275,148			2,561			112,005			1,120

Total Revenue		488,676			2,715			603,636			5,375			390,674			2,707

Lifting Costs		31,096			480			26,794			623			23,939			474
Gathering Costs		55,091			359			40,623			168			37,021			172
Royalty Expense		41,998			446			36,641			408			32,914			246
Other Production Costs		18,148			541			17,224			915			16,274			1,153
Purchased Gas Costs		44,843			299			278,720			2,434			113,063			1,044
DD&A		37,999			512			35,039			870			32,889			918

Total Costs		229,175			2,637			435,041			5,418			256,100			4,007

Pre-tax Operating Income		259,501			78			168,595			(43	)		134,574			(1,300	)
Income Taxes		97,728			29			65,280			(17	)		52,618			(508	)

Results of Operations excluding Corporate and Interest Costs	$	161,773		$	49		$	103,315		$	(26	)	$	81,956		$	(792	)

Net Reserve Quantity (Mcfe)
Beginning Reserves		1,127,724			2,672			1,042,403			2,385			1,002,800			1,581
Revisions		109,116			(584	)		57,575			521			33,539			—
Extensions and Discoveries		82,363			337			77,917			—			53,870			1,006
Production		(55,910	)		(225	)		(50,171	)		(234	)		(49,674	)		(202	)
Purchases of Reserves In-Place		—			—			—			—			1,868			—
Sales of Reserves In-Place		—			—			—			—			—			—

Ending Reserves		1,263,293			2,200			1,127,724			2,672			1,042,403			2,385

Proved Developed Reserves:
Beginning of Period		549,574			2,672			395,152			2,385			352,935			843

End of Period		609,700			2,200			549,574			2,672			395,152			2,385


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

CNX Gas proved gas reserves are located in the states of Virginia (97%), West Virginia (1%) and Pennsylvania (2%). CNX Gas’ proportionate interest in equity affiliates proved gas reserves is located in Tennessee (100%).

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

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,
	2006			2005			2004
Future Cash Flows:
Revenues	$	7,105,265		$	11,675,551		$	6,337,257
Production costs		(2,568,731	)		(2,852,033	)		(1,453,364	)
Development costs		(552,114	)		(422,315	)		(265,540	)
Income tax expense		(1,500,533	)		(3,251,265	)		(1,745,782	)

Future Net Cash Flows		2,483,887			5,149,938			2,872,571
Discounted to present value at a 10% annual rate		(1,548,996	)		(3,279,144	)		(1,843,033	)

Total standardized measure of discounted net cash flows	$	934,891		$	1,870,794		$	1,029,538

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


	December 31,
	2006			2005			2004
Balance at Beginning of Period	$	1,870,794		$	1,029,538		$	1,011,186
Net changes in sales prices and production costs		(5,341,525	)		3,539,448			262,723
Sales net of production costs		(438,174	)		(234,526	)		(219,937	)
Net change due to revisions in quantity estimates		1,492,654			632,547			364,456
Development costs incurred, previously estimated		169,169			110,916			87,274
Changes in estimated future development costs		(298,968	)		(267,691	)		(45,739	)
Net change in future income taxes		1,750,732			(1,505,484	)		(283,997	)
Accretion of discount and other		1,730,209			(1,433,954	)		(146,428	)

Total Discounted Cash Flow at End of Period	$	934,891		$	1,870,794		$	1,029,538

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


	Three Months Ended
	March 31,		June 30,		September 30,		December 31,
	2006		2006		2006		2006
Total Revenue and Other Income	$	148,223	$	122,852	$	123,567	$	119,217

Total Costs and Expense	$	73,286	$	60,532	$	61,770	$	61,831

Total Earnings Before Income Tax	$	74,937	$	62,320	$	61,797	$	57,386

Net Income	$	45,876	$	38,153	$	37,593	$	38,245

Earnings per Share
Basic	$	0.30	$	0.25	$	0.25	$	0.25

Diluted	$	0.30	$	0.25	$	0.25	$	0.25

Weighted Average Shares Outstanding
Basic		150,833,334		150,833,334		150,850,930		150,864,075

Dilutive		150,931,545		151,060,061		151,029,192		151,062,622


	Three Months Ended
	March 31,		June 30,		September 30,		December 31,
	2005		2005		2005		2005
Total Revenue and Other Income	$	106,050	$	111,072	$	176,312	$	220,007

Total Costs and Expense	$	62,919	$	83,442	$	133,497	$	166,865

Total Earnings Before Income Tax	$	43,131	$	27,630	$	42,815	$	53,142

Net Income	$	26,526	$	16,992	$	26,070	$	32,580

Earnings per Share
Basic	$	0.21	$	0.14	$	0.19	$	0.22

Diluted	$	0.21	$	0.14	$	0.19	$	0.22

Weighted Average Shares Outstanding
Basic		122,896,667		122,896,667		139,294,276		150,833,334

Dilutive		122,988,359		122,988,359		139,416,414		151,003,896


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

None.


ITEM 9A.		CONTROLS AND PROCEDURES

Disclosure controls and procedures.

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

Management’s Report on Internal Control Over Financial Reporting.

CNX Gas’ management is responsible for establishing and maintaining adequate internal control over financial reporting. CNX Gas’ internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.

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

Because of its inherent limitation, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of CNX Gas’ internal control over financial reporting as of December 31, 2006. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on its assessment and those criteria, management has concluded that CNX Gas maintained effective internal control over financial reporting as of December 31, 2006.

CNX Gas’ independent registered public accounting firm has audited and issued their report on management’s assessment of CNX Gas’ internal control over financial reporting, and the report is set forth in the Report of Independent Registered Public Accounting Firm in Part II, Item 8 of this Annual Report on Form 10-K.

Changes in Internal Controls Over Financial Reporting.

During the fourth quarter CNX Gas completed implementation of a new information management software platform. This project has resulted in certain changes to internal controls over financial reporting.


ITEM 9B.		OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The information required by this Item is incorporated herein by reference to the information under the captions “Proposal #1—Nominations for Election of Directors,” “General Information—The Board of Directors and Its Committees—The Board of Directors,” “General Information—The Board of Directors and Its Committees—Membership and Meetings of the Board of Directors and Its Committees” and “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for the annual meeting of shareholders to be held on April 23, 2007 (the “Proxy Statement”).

Executive Officers of CNX Gas Corporation

The following is a list of CNX Gas executive officers, their ages as of February 15, 2007 and their positions and offices held with CNX Gas.


Name	Age	Position
Nicholas J. DeIuliis	38	President and Chief Executive Officer and Director
Ronald E. Smith	58	Executive Vice President and Chief Operating Officer
Gary J. Bench	48	Senior Vice President and Chief Financial Officer
Stephen W. Johnson	48	Senior Vice President, Secretary and General Counsel

Nicholas J. DeIuliis, 38, has been President and Chief Executive Officer and a Director of CNX Gas since its formation on June 30, 2005. Prior to that, Mr. DeIuliis was Senior Vice President—Strategic Planning of CONSOL Energy from November 1, 2004 until August 8, 2005. Prior to that time, Mr. DeIuliis served as Vice President Strategic Planning from April 1, 2002 until November 1, 2004, Director—Corporate Strategy from October 1, 2001 to April 1, 2002, Manager—Strategic Planning from January 1, 2001 to October 1, 2001 and Supervisor—Process Engineering from April 1, 1999 to January 1, 2001, all of which positions he held at CONSOL Energy. Mr. DeIuliis is also a member of the Board of Directors of the Independent Petroleum Association of America and the Carnegie Science Center. Mr. DeIuliis is also a registered engineer in the Commonwealth of Pennsylvania and a member of the Pennsylvania Bar. He received a bachelor’s degree in chemical engineering from Pennsylvania State University and a master’s of business administration and juris doctorate from Duquesne University.

Ronald E. Smith, 58, has been CNX Gas’ Chief Operating Officer since June 30, 2005 and an Executive Vice President since December 5, 2005. Prior to that, Mr. Smith served as Executive Vice President—Gas Operations, Land Resources and Engineering Services of CONSOL Energy from April 1, 1992 to August 8, 2005. Mr. Smith joined CONSOL Energy in 1972. Mr. Smith has held numerous operating and management positions in various coal segments since he joined CONSOL Energy. Mr. Smith received a bachelor’s degree in Mining Engineering from Virginia Polytechnical Institute and State University and received that university’s distinguished alumnus award in 1998.

Gary J. Bench, 48, has been CNX Gas’ Chief Financial Officer since June 30, 2005 and became a Senior Vice President on December 5, 2005. Prior to that, Mr. Bench served as Vice President—Tax of CONSOL Energy from April 11, 2005 to August 8, 2005. Prior to that time, Mr. Bench was Controller—Tax from June 1, 2002 to April 11, 2005 and General Manager—Tax from July 1, 1999 to June 1, 2002, all of which positions he held at CONSOL Energy. Mr. Bench joined CONSOL Energy in 1985. Mr. Bench is also a member of the American Institute of Certified Public Accountants, the Pennsylvania Institute of Certified Public Accountants and the Tax Executive Institute. Mr. Bench received his bachelor’s degree in accounting from Indiana University of Pennsylvania and a master’s in taxation from Robert Morris University.

Stephen W. Johnson, 48, has been General Counsel of CNX Gas since September 1, 2005. He was named Senior Vice President as of December 5, 2005. Prior to joining CNX Gas, he was a partner since 2001 in the Business and Regulatory Group at Reed Smith LLP, an international law firm with about 1,000 lawyers. From 1984 to 2001, Mr. Johnson was with the law firm of Buchanan Ingersoll Professional Corporation. Mr. Johnson has served as corporate, securities and mergers and acquisitions counsel to both public and privately held companies for his entire professional career. Mr. Johnson is Vice Chairman of NEED, a non-profit organization that provides college scholarships to minority students, and a director of Concordia Lutheran Ministries, a non-profit continuing care retirement community serving thousands of elderly persons each year. Mr. Johnson received a bachelor’s degree in history from the University of Virginia and a juris doctor degree from the University of Pittsburgh School of Law.

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

ITEM 11. EXECUTIVE COMPENSATION.

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

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

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

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

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

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 19th day of February, 2007.


	CNX Gas Corporation
	By:	/s/ Nicholas J. DeIuliis
		Nicholas J. DeIuliis
		President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed as of the 19th day of February, 2007, by the following persons on behalf of the Registrant in the capacities indicated:


Signature				Title
/s/ Philip W. Baxter Philip W. Baxter				Chairman of the Board

/s/ Nicholas J. DeIuliis Nicholas J. DeIuliis				President, Chief Executive Officer and Director (Principal Executive Officer)

/s/ Gary J. Bench Gary J. Bench				Chief Financial Officer (Principal Financial and Accounting Officer)

/s/ J. Brett Harvey J. Brett Harvey				Director

/s/ James E. Altmeyer, Sr. James E. Altmeyer, Sr.				Director

/s/ Raj K. Gupta Raj K. Gupta				Director

/s/ John R. Pipski John R. Pipski				Director

/s/ William J. Lyons William J. Lyons				Director

/s/ Joseph T. Williams				Director
Joseph T. Williams

EXHIBIT INDEX


3.1		Amended and Restated Certificate of Incorporation of CNX Gas Corporation(1)

3.2		Amended and Restated Bylaws of CNX Gas Corporation(1)

4.1		Registration Rights Agreement dated August 8, 2005 by and among CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.(1)

4.2		Form of stock certificate(1)

10.1		Summary of Employment Terms for Nicholas J. DeIuliis(2)*

10.2		Offer letter for Ronald Smith(2)*

10.3		Offer letter for Gary J. Bench(1)*

10.4		Offer letter for Stephen W. Johnson(1)*

10.5		CNX Gas Corporation Equity Incentive Plan and form of award agreements thereunder(1)*

10.6.1		Form of Change in Control Agreement for executive officers DeIuliis and Bench(1)*

10.6.2		Form of Change in Control Agreement for executive officers Smith and Johnson(1)*

10.7		Master Separation Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each of the its subsidiaries (other than CNX Gas Corporation and its subsidiaries) and CNX Gas Corporation and its subsidiaries(3)

10.8		Master Cooperation and Safety Agreement dated as of August 1, 2005 by and among CONSOL Energy Inc. and each CEI Subsidiary (as defined therein) and CNX Gas Corporation and each CNX Subsidiary (as defined therein)(3)

10.9		Tax Sharing Agreement dated August 1, 2005 between CONSOL Energy Inc. and CNX Gas Corporation(3)

10.10		Services Agreement dated August 1, 2005 by and among CONSOL Energy Inc., CNX Land Resources Inc. and CNX Gas Corporation and its subsidiaries that become a party to the agreement(3)

10.11		Intercompany Revolving Credit Agreement between CONSOL Energy Inc. and CNX Gas Corporation(3)

10.12		Master Lease dated August 1, 2005 by and between CONSOL Energy Inc. and each of its subsidiaries made a party thereto and CNX Gas Company, LLC(3)

10.13		Summary sheet regarding director compensation(1)

10.14		Purchase/Placement Agreement dated August 1, 2005 by and between CNX Gas Corporation, CONSOL Energy Inc. and Friedman, Billings, Ramsey & Co., Inc.(1)

10.15		Credit Agreement dated October 7, 2005 between CNX Gas Corporation, certain of its subsidiaries, and the Lender parties thereto.(4)

10.16		Indenture, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(5)

10.17		Supplemental Indenture No. 1, dated March 7, 2002, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(6)

10.18		Supplemental Indenture No. 2, dated as of September 30, 2003, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(7)

10.19		Supplemental Indenture No. 3, dated as of April 15, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(8)

10.20		Supplemental Indenture No. 4, dated as of August 8, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(3)

10.21		Supplemental Indenture No. 5, dated as of October 21, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York, as trustee(9)


10.22		Precedent Agreement dated July 29, 2005 by and between East Tennessee Natural Gas, LLC and CNX Gas Company, LLC.(10)

10.23		Description of the CNX Gas Corporation 2006 Short-Term Incentive Compensation Program(11)*

10.24		Firm Transportation Agreement, dated as of April 27^th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC. (12)

10.25		Firm Lateral Transportation Agreement, dated as of April 27^th, 2006, between CNX Gas Company, LLC, a wholly-owned subsidiary of CNX Gas, and East Tennessee Natural Gas, LLC. (13)

10.26		The summary description of the base compensation and short-term incentive opportunities for the executive officers of CNX Gas Corporation for 2006.* (14)

10.27		The initial election grant of options to purchase common stock of CNX Gas Corporation to Joseph T. Williams, upon his election to the Board of Directors on July 10, 2006.* (15)

10.28		CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009 and form of award agreement thereunder.* (16)

10.29		First Amendment to the CNX Gas Corporation Equity Incentive Plan, as amended.* (16)

10.30		Summary of Non-Employee Director Compensation effective as of November 1, 2006.* (16)

10.31		Summary of the awards to CNX Gas Corporation’s executive officers under the CNX Gas Corporation Long-Term Incentive Program for the performance period from October 11, 2006 to December 31, 2009.* (16)

21		Subsidiaries of CNX Gas Corporation(1)

23.1		Consent of PricewaterhouseCoopers LLP

23.2		Consent of Ralph E. Davis Associates, Inc.

23.3		Consent of Schlumberger Data and Consulting Services

31.1		Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2		Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


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

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

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

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

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

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

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

(8)		Incorporated by reference from Exhibit 4.2 to Form 10-Q filed by CONSOL Energy Inc. on August 3, 2005

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

(10)		Incorporated by reference from the Amendment No. 4 to the Registration Statement on Form S-1 (file no. 333-127483) filed on December 17, 2005

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


		Page
PART I
Item 1.	Business		4
Item 1A.	Risk Factors		22
Item 1B.	Unresolved Staff Comments		30
Item 2.	Properties		30
Item 3.	Legal Proceedings		31
Item 4.	Submission of Matters to a Vote of Security Holders		32
	Executive Officers of CNX Gas Corporation

PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		33
Item 6.	Selected Financial Data		35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		52
Item 8.	Financial Statements and Supplementary Data		53
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosures		86
Item 9A.	Controls and Procedures		86
Item 9B.	Other Information		87

PART III
Item 10.	Directors and Executive Officers of the Registrant		87
Item 11.	Executive Compensation		88
Item 12.	Security Ownership of Certain Beneficial Owners and Management		88
Item 13.	Certain Relationships and Related Transactions		88
Item 14.	Principal Accounting Fees and Services		89

PART IV
Item 15.	Exhibits and Financial Statement Schedules		89
SIGNATURES			90
Ex-23.1
Ex-23.2
Ex-23.3
Ex-31.1
Ex-31.2
Ex-32.1
Ex-32.2


*Kentucky*
Bell	Breathitt	Clay
Crittenden	Estill	Floyd
Harlan	Henderson	Hopkins
Jackson	Johnson	Knott
Knox	Lee	Leslie
Letcher	Magoffin	McLean
Muhlenberg	Owsley	Perry
Pike	Pulaski
Rockcastle	Union	Webster
Whitley	Wolfe

*Virginia*
Bland	Buchanan	Carroll
Culpeper	Dickenson	Russell
Tazewell	Washington	Wythe

*West Virginia*
Braxton	Clay	Lewis
Logan	McDowell	Mercer
Mingo	Nicholas	Pocahontas
Raleigh	Randolph	Upshur
Webster	Wyoming

*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*
Claiborne	Morgan	Campbell
Scott	Roane	Anderson

*New York*
Allegany	Steuben

*Illinois*
Gallatin	Hamilton	Hardin
Jefferson	Pope	Williamson


(a)(1)		Financial Statements:

		The financial statements included in Part II, Item 8 above are filed as part of this annual report.

(a)(2)		Financial Statement Schedules:

		No schedules are required to be presented by CNX Gas.

(a)(3) and (b)		Exhibits:

		The exhibits listed on the Exhibit Index which follows the Signatures hereto are filed as part of this annual report.


		Corporation on February 10, 2006

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

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

(14)		Incorporated by reference from Item 1.01 of the Current Report on Form 8-K filed by the CNX Gas Corporation on May 1, 2006 (SEC File No. 001-32723)

(15)		Incorporated by reference from Item 1.01 of the Current Report on Form 8-K filed by CNX Gas Corporation on July 11, 2006 (SEC File No. 001-32723)

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

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

*		Management compensatory contract or arrangement.


		RALPH E. DAVIS ASSOCIATES, INC.

		/s/ Allen C. Barron

		Allen C. Barron, P.E.
		President



1717 St. James Place, Suite 460	Houston, Texas 77056	Office 713-622-6955	Fax 713-626-3664	www.ralphdavis.com
Worldwide Energy Consultants Since 1924


1310 Commerce Drive Park Ridge 1 Pittsburgh, PA 15275-1011
Tel. 412-787-5403
Fax: 412-787-2906


		/s/ Nicholas J. DeIuliis

		Nicholas J. DeIuliis
		President, Chief Executive Officer and Director


		/s/ Gary J. Bench

		Gary J. Bench
		Senior Vice President and Chief Financial Officer