Except as otherwise noted or unless the context otherwise requires, (i) the information in this Annual Report on Form 10-K gives effect to the contribution to CNX Gas of the CONSOL Energy gas business effective as of August 8, 2005, (ii) CNX Gas refers, with respect to any date prior to the effective date of that contribution, to the CONSOL Energy gas business and, with respect to any date on or subsequent to the effective date of the contribution, to CNX Gas and our subsidiaries, (iii) “CONSOL Energy” refers to CONSOL Energy Inc. and its subsidiaries other than CNX Gas and the companies which conducted CONSOL Energy’s gas business, and (iv) reserve and operating data are as of December 31, 2008 unless otherwise indicated. The estimates of our proved reserves as of December 31, 2008, 2007, 2006 and 2005 included in this Annual Report are based on reserve reports prepared by Schlumberger Data and Consulting Services. The estimates of our proved reserves as of December 31, 2004 (set forth in Item 6, “Selected Financial Data—Other Financial Data”) are based on reserve reports prepared by Ralph E. Davis Associates, Inc. and Schlumberger Data and Consulting Services. Unless otherwise noted, we discuss production, per unit revenue and per unit costs net of any royalty owners’ interest. With respect to production and reserves, we use the word “net” to indicate when a number does not include the royalty owners’ interest. With respect to acres, we use the word “net” to describe our aggregate fractional interest in property that we control by deed or lease. With the exception of earnings per share data, we discuss dollars in millions throughout this Form 10-K. Financial information concerning industry segments, as defined by accounting principles generally accepted in the United States of America, for the year ended December 31, 2008, 2007 and 2006 is included in Note 20 to the Consolidated Financial Statements included as Item 8 in Part II of this Annual Report on Form 10-K.

General

We are engaged in the exploration, development, production and gathering of natural gas primarily in the Appalachian and Illinois Basins. In particular, we are a leading developer of coalbed methane (CBM) and we have a growing conventional and shale exploration program. CONSOL Energy Inc. (CONSOL Energy) owns 83.3% of our outstanding common stock. In August 2005, we acquired all of CONSOL Energy’s rights associated with CBM from 4.5 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia, Central Appalachia, the Illinois Basin and other western basins. CONSOL Energy also transferred ownership or rights to natural gas, oil and certain related surface properties. As of December 31, 2008, we had 1.422 Tcfe of net proved reserves, with a PV-10 value of $2.0 billion and a standardized measure of discounted after tax future net cash flows attributable to our proved reserves of $1.2 billion. Our proved reserves are approximately 97% CBM and 55% proved developed. We are one of the largest gas producers in the Appalachian Basin with net sales of 76.6 Bcf for the year ended December 31, 2008. Our proved reserves are long-lived with a reserve life index of 18.6 years.

History of CNX Gas

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

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

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

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

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

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

Our Relationship with CONSOL Energy

Prior to August 2005 we conducted business through various companies that were subsidiaries or joint ventures of CONSOL Energy, a public company traded on the NYSE under the symbol “CNX.”

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

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

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

Coordination with Mining Activities

Approximately 24% of our 2008 gas production is produced in connection with coal extraction by CONSOL Energy. It is essential that gas liberated by the mining process be removed from the mine in order to maintain a safe working environment in the mine. As a result, a portion of our gas extraction activity is determined based upon the needs of the related mining activity.

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

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Management Reorganization

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

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

Gas Operations

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

Areas of Operation

In the Appalachian Basin we operate principally in Central Appalachia and Northern Appalachia, which represent our two reportable segments. We also operate in the Illinois Basin. Our primary operating areas are:

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In addition to the above areas, we believe we have Appalachian shale potential in the Marcellus, Huron, and Chattanooga shales. Additional potential exists in the Trenton Black River formation which is thought to underlie nearly all of the Appalachian shales. We will continue to evaluate our acreage position in these areas with the continuation of our exploration program.

Central Appalachia

Virginia Operations CBM

We have the right to extract CBM in this region from approximately 418,000 net CBM acres, which cover a portion of coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We acquired CONSOL Energy’s rights associated with CBM in this region upon inception. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of 2,000 feet and generally ranges from 3 to 6 feet thick. The gas content of this seam is typically between 400 and 600 cubic feet of gas per ton of coal in place. In addition, there are as many as 50 thinner seams present in the several hundred feet above the main Pocahontas #3 seam. Collectively, this series of coal seams represents a total thickness ranging from 15 to 40 feet. We have access to over 1,300 core holes that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

We coordinate some of our CBM extraction with the subsurface coal mining of CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam ahead of the planned mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a “frac well.” In 2008, frac wells account for approximately 74% of our Virginia production.

Because some of our gas is produced in association with subsurface mining, we have a unique opportunity to evaluate the effectiveness of our fracture techniques. We can enter the coal mine and inspect the fracture pattern created in the seam as the mining process exposes more of the coal. As a result, we have had the opportunity to gain insight into the efficiency of our fracturing techniques that is not available in a conventional production scenario. We have used this knowledge to modify and improve the effectiveness of our fracturing techniques.

Eventually, subsurface mining activities will mine through the frac wells that are drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a “panel”), a rubble zone (called “gob”) is formed in the cavity created by the extraction of the coal. When the coal is removed, the rock above collapses into the void. These upper seams become extensively fractured and release substantial volumes of gas. We drill vertical wells (called “gob wells”) into the gob to extract the additional gas that is released. The extraction of gas from active gob areas generally is completed within twelve months of the start of production. Approximately 12% of our Virginia gas production comes in the form of gob gas from active coal operations.

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We also drill long horizontal wellbores into the coal seam from within active mines. We strategically locate these horizontal wells within the pattern of existing frac wells to further accelerate the desorption of CBM from the coal seam. Over the past several years, we have drilled 15 of these “in-mine” horizontal wells, some of which have been extended to lengths of 5,000 feet. These wells show that a more efficient recovery of gas in place is possible ahead of mining operations. The production rates from frac wells have not been adversely impacted by the introduction of nearby horizontal wellbores in the coal seam. In fact, we believe production at offsetting frac wells has actually increased due to the further reductions in pressure within the coal seam caused by the horizontal wells. We intend to increase our use of the horizontal wells drilled within an active mine in our future development plans. In-mine horizontal wells accounted for approximately 1% of Virginia production in 2008.

Virginia Operations Shale and Tight Sands

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

Tennessee

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

Northern Appalachia

Mountaineer CBM

We have the right to extract CBM in this region from approximately 783,000 net CBM acres, which contain most of the recoverable coal reserves owned or controlled by CONSOL Energy in Northern Appalachia. We have acquired all of CONSOL Energy’s rights associated with CBM in this region. We produce gas primarily from the Pittsburgh #8 coal seam. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas content of this seam is typically between 100 and 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh #8 seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30 feet. We have access to over 7,000 data points that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.

Due to the significant geological differences between the Pittsburgh #8 seam in Mountaineer and the Pocahontas #3 seam in Virginia, we have found that alternative extraction techniques are more effective than vertical frac wells in this area. Instead of using frac wells, we utilize well designs that rely on the application of vertical-to-horizontal drilling techniques. This well design includes a vertical wellbore that is intersected by a second well that has up to four horizontal lateral sections in the coal. Together, this well system facilitates extraction of CBM and water from the coal seam. The horizontal wellbores, extending up to 5,000 feet from the point of intersection with the vertical wellbore, expose large amounts of coal surface area allowing for the migration of water and CBM from the coal seam. The wells are spaced on approximately 480 acre sections. The vertical well, equipped with a mechanical pump, provides a sump for water produced by the coal seam to collect and enables the collected water to be lifted to the surface for disposal. In addition to our vertical-to-horizontal drilling, we also develop gob wells in this region associated with CONSOL Energy’s mines.

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Nittany CBM

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

Marcellus Shale

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

Shallow Oil and Gas

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

Others

Cardinal Shale

As of December 31, 2008, we controlled approximately 338,000 net acres of rights to gas in the New Albany shale in Kentucky, Illinois, and Indiana. The New Albany shale is a formation containing gaseous hydrocarbons, and our acreage position has thickness of 50-300 feet at an average depth of 2,500-4000 feet. As of December 31, 2008, we have identified test well locations and we have drilled several exploratory wells. We are using a standard drilling rig to drill up to 4,000 vertical feet. We also have identified the potential for shallow oil in this area which we will continue to evaluate.

Illinois Basin CBM

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

Other Acreage

We have the right to extract CBM on 139,000 net acres in the San Juan Basin, 34,000 net acres in the Powder River Basin, 41,000 net acres in eastern Ohio, and 51,000 net acres in central West Virginia. We also have the right to extract oil and gas on 12,000 net acres in the San Juan Basin, 10,000 net acres in the Powder River Basin, and 40,000 net acres in various other areas.

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Drilling

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

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

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Summary of Other Operating Data

Production

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

Average Sales Prices and Lifting Costs

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

Productive Wells and Acreage

Most of our development wells and acreage are located in Central Appalachia. Some leases are beyond their primary term, but these leases are extended in accordance with their terms as long as certain drilling commitments are satisfied. The following table sets forth, at December 31, 2008, the number of CNX Gas producing wells, developed acreage and undeveloped acreage:

Sales

CNX Gas enters into physical gas sales transactions with various counterparties for terms varying in length. Reserves and production estimates are believed to be sufficient to satisfy these obligations. In the past, other than interstate pipeline outages related to maintenance issues, we have not failed to deliver quantities required under

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contract. CNX Gas has also entered into various gas swap transactions that qualify as financial cash flow hedges. These gas swap transactions exist parallel to the underlying physical transactions and represented approximately 43.4 Bcf of our produced gas sales volumes for the year ended December 31, 2008 at an average price of $9.25 per Mcf. As of December 31, 2008, we expect these transactions will cover approximately 41.9 Bcf of our estimated 2009 production at an average price of $9.74 per Mcf.

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

The hedging strategy and information regarding derivative instruments used are outlined in “Management’s Discussion and Analysis of Results of Operations and Financial Condition—Qualitative and Quantitative Disclosures About Market Risk,” and in Note 18 to the Consolidated Financial Statements.

Reserves

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

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Competition

We operate primarily in the eastern United States. We believe that the gas market is highly fragmented and not dominated by any single producer. We believe that several of our competitors have devoted far greater resources than we have to gas exploration and development. We believe that competition within our market is based primarily on gas commodity trading fundamentals and pipeline transportation availability to the diverse market opportunities.

Employee and Labor Relations

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

Available Information

We file annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and proxy statements and other documents with the Securities and Exchange Commission (SEC) pursuant to the Securities Exchange Act of 1934. All documents that we file with the SEC are available for reading and copying in the SEC’s public reference room located at 100 F Street, N.E., Washington, D.C. 20549. Please contact the SEC at 1-800-SEC-0330 for further information regarding the operations of the public reference room. These SEC filings are also available over the Internet at the SEC’s website, www.sec.gov .

We make copies of these documents available on our own Internet website, www.cnxgas.com , as soon as reasonably possible after we have furnished such information to the SEC. Information contained on or connected to our website which is not directly incorporated by reference into this Form 10-K should not be considered part of this report or any other filing that we make with the SEC.

In addition, the charter for the audit committee of our Board of Directors and our Code of Ethics and Business Conduct, one for directors and the other for employees, can be found on our Internet website under the heading “Corporate Governance.” Stockholders may request copies of these documents by writing to the Investor Relations Department at 5 Penn Center West, Suite 401, Pittsburgh, Pennsylvania 15276-0102. Our Code of Employee Business Conduct and Ethics applies to CNX Gas’ Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer), principal accounting officer or controller and persons performing similar functions. If CNX Gas makes any amendments to the code other than technical, administrative, or other non-substantive amendments, or grants any waivers, including implicit waivers, from a

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provision of the code applicable to its principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, CNX Gas will disclose the nature of the amendment or waiver, its effective date and to whom it applies on our website or in a report on Form 8-K filed with the Securities and Exchange Commission.

Regulations

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

Environmental Regulation of Gas Operations

Numerous governmental permits and approvals are required for gas operations. In order to obtain such permits and approvals, we are, or may be, required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of gas may have upon the environment and public and employee health and safety. Compliance with such permits and all other requirements imposed by such authorities may be costly and time-consuming and may delay the commencement or continuation of exploration or production operations. Moreover, failure to comply may result in the imposition of significant fines and penalties. Future legislation or regulations may increase and/or change the requirements for the protection of the environment, health and safety and, as a consequence, our activities may be more closely regulated. This type of legislation and regulation, as well as future interpretations of existing laws, may result in substantial increases in equipment and operating costs to CNX Gas and delays, interruptions or a termination of operations, the extent of which cannot be predicted. Further, the imposition of new environmental regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas. Furthermore, new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may also increase operating costs and cause delays, interruptions or termination of operations, the extent of which cannot be predicted. It is not possible to quantify the costs of compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the year ended 2008, 2007 and 2006 . Any environmental costs are in addition to well plugging costs; property restoration costs; and other, significant, non-capital environmental costs, including costs incurred to obtain and maintain permits and bonds, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management and operational practices with regard to potential environmental liabilities. Compliance with these federal and state environmental laws has increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.

The magnitude of the liability and the cost of complying with environmental laws and regulations cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling, remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the future and such environmental liabilities or costs could adversely affect our results

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and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances; environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for treatment or disposal.

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

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

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

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

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

Federal Regulation of the Sale and Transportation of Gas

Various aspects of CNX Gas’ operations are regulated by agencies of the federal government. The Federal Energy Regulatory Commission regulates the transportation and sale of natural gas in interstate commerce pursuant to the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. While “first sales” by producers

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of natural gas, and all sales of condensate and natural gas liquids can be made currently at uncontrolled market prices, Congress could reenact price controls in the future. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all Natural Gas Act and Natural Gas Policy Act price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993.

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

The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance with state law. In addition, the Federal Energy Regulatory Commission’s approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to interested producers or shippers in the future.

CNX Gas owns certain natural gas pipeline facilities that we believe meet the traditional tests which the Federal Energy Regulatory Commission has used to establish a pipeline’s status as a gatherer not subject to the Federal Energy Regulatory Commission jurisdiction.

Additional proposals and proceedings that might affect the gas industry may be pending before Congress, the Federal Energy Regulatory Commission, the Minerals Management Service, state commissions and the courts. CNX Gas cannot predict when or whether any such proposals may become effective. In the past, the natural gas industry has been heavily regulated. There is no assurance that the regulatory approach currently pursued by various agencies will continue indefinitely. Notwithstanding the foregoing, CNX Gas does not anticipate that compliance with existing federal, state and local laws, rules and regulations will have a material or significantly adverse effect upon the capital expenditures, earnings or competitive position of CNX Gas or its subsidiaries. No material portion of CNX Gas’ business is subject to renegotiation of profits or termination of contracts or subcontracts at the election of the federal government.

State Regulation of Gas Operations

CNX Gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location and spacing of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, the disposal of fluids used in connection with operations, and gas operations producing coalbed methane in relation to active mining. CNX Gas’ operations are also subject to various conservation laws and regulations. These include regulations that affect the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas wells, and generally prohibit the venting or flaring of gas and impose certain requirements regarding the ratability of production. A number of states have either enacted new laws or may be considering the adequacy of existing laws affecting gathering rates

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and/or services. Other state regulation of gathering facilities generally includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CNX Gas’ gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CNX Gas does not believe that we would be affected by such regulation any differently than other natural gas producers or gatherers. However, these regulatory burdens may affect profitability, and CNX Gas is unable to predict the future cost or impact of complying with such regulations.

Ownership of Mineral Rights

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

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

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

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

Pennsylvania

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

Virginia

The vast majority of CBM we produce, as well as our proved reserves, are in Virginia. The Virginia Supreme Court has stated that the grant of coal rights only does not include rights to CBM absent an express grant of CBM, natural gases, or minerals in general. The situation may be different if there is any expression in

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the severance deed indicating more than mere coal is conveyed. Virginia courts have also found that the owner of the CBM did not have the right to fracture the coal in order to retrieve the CBM and that the coal operator had the right to ventilate the CBM in the course of mining. In Virginia, we believe that we control the relevant property rights in order to capture gas from the vast majority of our producing properties.

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

West Virginia

The West Virginia’s Supreme Court has held that, in a conventional oil and gas lease executed prior to the inception of widespread public knowledge regarding CBM operations, the oil and gas lessee did not acquire the right to produce CBM. As of December 31, 2008, the West Virginia courts have not clarified who owns CBM in West Virginia. Therefore, the ownership of CBM is an open question in West Virginia.

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

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

Other States

We have been transferred rights to extract CBM held by CONSOL Energy in other states where they have coal reserves, including the states which comprise the Illinois Basin and certain other western basins. The ownership of CBM in these other states may be uncertain or could belong to other holders of real estate interests and we may need to acquire additional rights from other holders of real estate interests to extract and produce CBM in these other states.

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GLOSSARY OF NATURAL GAS AND COAL TERMS

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

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

Bcf . Billion cubic feet of natural gas.

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

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

CBM . Coalbed methane.

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

Coal Seam. A single layer or stratum of coal.

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

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

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

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

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

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

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

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

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

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

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

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

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

Mcf . Thousand cubic feet of natural gas.

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

MMBtu . Million British thermal units.

Mmcf . Million cubic feet of natural gas.

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

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

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

NYMEX. The New York Mercantile Exchange.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Executive Officers Of The Company

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

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