##### Table of Contents

---

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

---

FORM 10-K

---

(Mark One)

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

For the fiscal year ended December 31, 2005;

OR

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

For the transition period fromto

Commission file number: 001-32723

---

CNX GAS CORPORATION

(Exact name of registrant as specified in its charter)

---

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

4000 Brownsville Road

South Park, PA 15129-9545

(412) 854-6719

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

---

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

|                              |  |                                          
|----------------------------- |  | -----------------------------------------
|Title Of Each Class           |  | Name of Each Exchange On Which Registered
|Common Stock ($.01 par value) |  | New York Stock Exchange                  

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

---

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90
days.    Yes ̈No  x

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

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

|                         |  |                    |  |                         
|------------------------ |  | ------------------ |  | ------------------------
|Large accelerated filer ̈ |  | Accelerated filer ̈ |  | Non-accelerated filer  x

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

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

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

DOCUMENTS INCORPORATED BY REFERENCE:

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

---



---

##### Table of Contents

TABLE OF CONTENTS



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



2



---

##### Table of Contents

FORWARD-LOOKING STATEMENTS



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



| |  |  | our business strategy;
| | - |  | ----------------------



| |  |  | our financial position;
| | - |  | -----------------------



| |  |  | our cash flow and liquidity;
| | - |  | ----------------------------



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



| |  |  | uncertainties in estimating our gas reserves;
| | - |  | ---------------------------------------------



| |  |  | replacing our gas reserves;
| | - |  | ---------------------------



| |  |  | uncertainties in exploring for and producing gas;
| | - |  | -------------------------------------------------



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



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



| |  |  | competition in the gas industry;
| | - |  | --------------------------------



| |  |  | our inability to retain and attract key personnel;
| | - |  | --------------------------------------------------



| |  |  | our joint venture arrangements;
| | - |  | -------------------------------



| |  |  | the effects of government regulation and permitting and other legal requirements;
| | - |  | ---------------------------------------------------------------------------------



| |  |  | costs associated with perfecting title for gas rights in some of our properties;
| | - |  | --------------------------------------------------------------------------------



| |  |  | our need to use unproven technologies to extract coalbed methane in some properties;
| | - |  | ------------------------------------------------------------------------------------



| |  |  | our relationships and arrangements with CONSOL Energy; and
| | - |  | ----------------------------------------------------------



| |  |  | other factors discussed under Risk Factors.
| | - |  | ---------------------------------------------



3



---

##### Table of Contents

PART I



ITEM 1. BUSINESS



General



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



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



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



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



4



---

##### Table of Contents

History of CNX Gas



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



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



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



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



Recent Events



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



Our Relationship with CONSOL Energy



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



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



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



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



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



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



5



---

##### Table of Contents

The success of our operations substantially depends upon rights we received from CONSOL Energy. As a part
of our separation from CONSOL Energy, CONSOL Energy transferred to CNX Gas various subsidiaries and joint venture interests as well as all of CONSOL Energys ownership or rights to CBM, natural gas, oil, and certain related surface rights.
There were however, certain other property interests that were retained by CONSOL Energy and not conveyed to CNX Gas. These retained assets, which included, for example, assets associated with gas well plugging, had an aggregate book value of $6.6
million and are not material to the business and operations of CNX Gas. In addition, CONSOL Energy has given us significant rights to conduct gas production operations associated with its coal mining activity. These rights are not dependent upon any
continuing ownership in us by CONSOL Energy. We also have established other agreements with CONSOL Energy under which they will provide us certain corporate staff services and coordinate our tax filings.



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



Coordination with Mining Activities



Approximately 17% of our current gas production is
produced as a consequence of coal extraction by CONSOL Energy (not including another approximately 16% of our production that is associated with previously mined areas). It is essential that gas liberated by the mining process be captured and
removed from the mine in order to maintain a safe working environment in the mine. As a result, a portion of our gas extraction activity is determined based upon the needs of the related mining activity.



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



Other Assets



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



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



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



6



---

##### Table of Contents

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



Gas Operations



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



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



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



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



Areas of Operation



We
operate in these principal areas of the Appalachian Basin:



Central Appalachia



We have the right
to extract CBM in this region from approximately 296,000 net CBM acres, which contain most of the over 400 million tons of proved coal reserves owned or controlled by CONSOL Energy in Central Appalachia. We have acquired all of CONSOL
Energys rights associated with CBM in this region. We produce gas primarily from the Pocahontas #3 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of 2,000 feet and generally
ranges from 3 to 6 feet thick. The gas content of this seam contains on average 400 to 600 cubic feet of gas per ton of coal in place. In addition, there



7



---

##### Table of Contents

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



We coordinate some of our CBM extraction with the subsurface coal mining of
CONSOL Energy. The initial phase of CBM extraction involves drilling a traditional vertical wellbore into the coal seam in advance of future mining activities. In general, we drill these wells into the coal seam 5 to 10 years ahead of the planned
mining recovery in an area. To stimulate the flow of CBM to the wellbore, we fracture the coal seam by pumping water or inert gases into the coal seam. Once established, these fractures are maintained by further forcing sand into the fractures to
keep them from closing, allowing CBM to desorb from the coal and migrate along the series of fractures into the wellbore. We refer to this type of well as a frac well. Presently, frac wells account for approximately 67% of our daily
production.



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



Eventually, subsurface mining activities will mine
through the frac wells drilled in advance of the mine development plan. As the main coal seam is removed from an area (called a panel), a rubble zone (called gob) is created in the cavity created by the extraction of the
coal. When the coal is removed, the rock above, which includes as many as 50 thinner, unminable coal seams, collapses into the void. These seams become extensively fractured and release substantial volumes of gas as they collapse. We drill vertical
wells (called gob wells) into the gob to extract the additional gas that is released. Approximately 32% of our gas production comes in the form of gob gas (16% active gob and 16% sealed gob). CONSOL Energy pays for the drilling of our
gob wells in most instances.



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



Northern Appalachia



We have the right to extract CBM in this region from
approximately 408,000 net CBM acres, which contain most of the over 2.7 billion tons of proved coal reserves owned or controlled by CONSOL Energy in Northern Appalachia. We have acquired all of CONSOL Energys rights associated with CBM in this
region. We produce gas primarily from the Pittsburgh #8 seam which is the main coal seam mined by CONSOL Energy in this region. This seam is generally found at depths of less than 1,000 feet and generally ranges from 4 to 7 feet thick. The gas
content of this seam is about 100 to 250 cubic feet of gas per ton of coal in place. There are additional coal seams above and below the Pittsburgh seam. Collectively, this series of coal seams represents a total thickness ranging from 10 to 30
feet. We have access to over 7,000 core samples that allow us to determine the amount of coal present, the geologic structure of the coal seam and the gas content of the coal.



8



---

##### Table of Contents

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



Tennessee



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



Illinois and Other Western Basins



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



9



---

##### Table of Contents

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



Central Appalachia Region



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



10



---

##### Table of Contents

Summary of Appalachian Basin Properties as of December 31, 2005



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

---

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

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



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



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



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



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

---

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



11



---

##### Table of Contents

Recent Drilling Activity (net wells)



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



Drilling



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



Development Wells



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



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



Exploratory Wells



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



12



---

##### Table of Contents

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



Summary of Other Operating Data



Production



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



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



Average Sales
Prices and Lifting Costs



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



|                                                                            |  |                                 |      |      |   |      |  |   |     
|--------------------------------------------------------------------------- |  | ------------------------------- | ---- | ---- | - | ---- |  | - | ----
|                                                                            |  | Twelve Months EndedDecember 31,
|                                                                            |  | 2005                            |      | 2004 |   | 2003
|Average Gas Sales Price Including Effects of FinancialSettlements (per mcf) |  | $                               | 6.08 |      | $ | 5.09 |  | $ | 4.14
|Average Lifting Cost (per mcf)                                              |  | $                               | 0.57 |      | $ | 0.50 |  | $ | 0.48



Productive Wells
and Acreage



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



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



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



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



13



---

##### Table of Contents

Sales



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



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



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



The hedging strategy and information regarding derivative instruments used
are outlined in Managements Discussion and Analysis of Results of Operations and Financial ConditionQualitative and Quantitative Disclosures About Market Risk, and in Note 17 of the notes to the consolidated annual financial
statements included in Item 8 of Part II of this Annual Report.



Gathering



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



Transportation



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



14



---

##### Table of Contents

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



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



Reserves



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



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



Discounted Future
Net Cash Flows



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



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

---

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



15



---

##### Table of Contents

| | estimated to be paid, the use of a pre-tax measure is valuable when comparing companies based on reserves. PV-10 is not a measure of financial or operating
performance under GAAP. PV-10 should not be considered as an alternative to the standardized measure as defined under GAAP. We have included a reconciliation to the most directly comparable GAAP measureafter tax discounted future net cash
flows.
| | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



Reconciliation of PV-10 to
Standardized Measure:



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



Competition



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



Subsidiaries and Joint Ventures



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



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



Knox Energy LLC



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



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



16



---

##### Table of Contents

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



Coalfield Pipeline Company



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



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



Buchanan Generation, LLC



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



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



Employee and Labor Relations



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



Regulations



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



17



---

##### Table of Contents

Environmental Regulation of Gas Operations



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



It is not possible to quantify the costs of
compliance with all applicable federal and state environmental laws. While those costs have not been significant in the past, they could be significant in the future. CNX Gas had no significant environmental control facility expenditures for the
twelve months ended 2005, 2004 and 2003. CNX Gas expects to incur $1.1 million related to water disposal wells in 2006. Any environmental costs are in addition to well closing costs; property restoration costs; and other, significant, non-capital
environmental costs, including costs incurred to obtain and maintain permits, to gather and submit required data to regulatory authorities, to characterize and dispose of wastes and effluents, and to maintain management operational practices with
regard to potential environmental liabilities. Compliance with these federal and state environmental laws has substantially increased the cost of gas production, but is, in general, a cost common to all domestic gas producers.



The magnitude of the liability and the cost of complying with environmental
laws cannot be predicted with certainty due to: the lack of specific environmental, geologic, and hydrogeologic information available with respect to many sites; the potential for new or changed laws and regulations; the development of new drilling,
remediation, and detection technologies and environmental controls; and the uncertainty regarding the timing of work with respect to particular sites. As a result, we may incur material liabilities or costs related to environmental matters in the
future and such environmental liabilities or costs could adversely affect our results and financial condition. In addition, there can be no assurance that changes in laws or regulations would not affect the manner in which we are required to conduct
our operations. Further, given the retroactive nature of certain environmental laws, CNX Gas has incurred, and may in the future incur, liabilities associated with: the investigation and remediation of the release of hazardous substances;
environmental conditions; and natural resource damages related to properties and facilities currently or previously owned or operated as well as sites owned by third parties to which CNX Gas or our subsidiaries sent waste materials for disposal.



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



| |  |  | the Clean Air Act;
| | - |  | ------------------



| |  |  | the Clean Water Act;
| | - |  | --------------------



| |  |  | the Toxic Substances Control Act;
| | - |  | ---------------------------------



| |  |  | the Endangered Species Act:
| | - |  | ---------------------------



| |  |  | the Resource Conservation and Recovery Act; and
| | - |  | -----------------------------------------------



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



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



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



18



---

##### Table of Contents

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



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



Federal Regulation of the Sale
and Transportation of Gas



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



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



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



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



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



19



---

##### Table of Contents

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



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



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



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



The
new reporting requirements became effective on September 1, 2000. The Federal Energy Regulatory Commission has also issued numerous orders confirming the sale and abandonment of natural gas gathering facilities previously owned by interstate
pipelines and acknowledging that if the Federal Energy Regulatory Commission does not have jurisdiction over services provided by these facilities, then such facilities and services may be subject to regulation by state authorities in accordance
with state law. A number of states have either enacted new laws or are considering the adequacy of existing laws affecting gathering rates and/or services. Other state regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, nondiscriminatory take requirements, but does not generally entail rate regulation. Thus, natural gas gathering may receive greater regulatory scrutiny of state agencies in the future. CNX Gas
gathering operations could be adversely affected should they be subject in the future to increased state regulation of rates or services, although CNX Gas does not believe that it would be affected by such regulation any differently than other
natural gas producers or gatherers. In addition, the Federal Energy Regulatory Commissions approval of transfers of previously-regulated gathering systems to independent or pipeline affiliated gathering companies that are not subject to
Federal Energy Regulatory Commission regulation may affect competition for gathering or natural gas marketing services in areas served by those systems and thus may affect both the costs and the nature of gathering services that will be available to
interested producers or shippers in the future.



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



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



State Regulation of Gas OperationsUnited States



CNX Gas operations are also subject to regulation at the state and in some cases, county, municipal and local governmental levels. Such regulation
includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties
upon which wells are drilled, the plugging and abandoning of wells and the disposal of fluids used in connection with operations. CNX Gas operations are also subject to various conservation laws and regulations. These include regulations that
affect the size of drilling and spacing units or proration units and the density of wells which may be drilled and the unitization or pooling of gas properties. In addition, state conservation laws establish maximum rates of production from gas
wells,



20



---

##### Table of Contents

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



Ownership of Mineral Rights



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



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



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



Pennsylvania



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



Virginia



The vast
majority of CBM we produce as well as our proven reserves are in Virginia, which has been the focus of our developmental efforts to date. In Virginia, the Virginia Supreme Court has stated that the grant of coal rights only does not include rights
to CBM absent an express grant of CBM, natural gases, or minerals in general. The situation may be different if there is any expression in the severance deed indicating more than mere coal is conveyed. This Court has also found that the owner of the
CBM did not have the right to fracture the coal



21



---

##### Table of Contents

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



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



West Virginia



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



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



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



Other States



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



22



---

##### Table of Contents

GLOSSARY OF NATURAL GAS AND COAL TERMS



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



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



Bcf. Billion cubic feet of natural gas.



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



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



CBM. Coalbed methane.



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



Coal Seam. A single layer or stratum of coal.



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



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



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



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



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



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



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



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



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



23



---

##### Table of Contents

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



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



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



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



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



mcf. Thousand cubic feet of natural gas.



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



MMBtu. Million British thermal units.



mmcf. Million cubic feet of natural gas.



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



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



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



NYMEX. The New York
Mercantile Exchange.



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



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



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



24



---

##### Table of Contents

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



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



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



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



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



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



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



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



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



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



EXECUTIVE
OFFICERS OF THE COMPANY



Incorporated by reference into
this Part I is the information set forth in Part III, Item 10 under the caption Officers of the Registrant (included herein pursuant to Item 401(b) of Regulation S-K).



25



---

##### Table of Contents

ITEM 1A. RISK FACTORS



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



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



Our revenue, profitability and cash flow depend upon the prices and demand for natural gas and oil. The markets for these commodities are very volatile
and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in natural gas and oil prices have a significant impact on the value of our reserves and on our cash flow. In the past we have
used hedging transactions to reduce our exposure to market price volatility when we deemed it appropriate. However, in 2006 we expect to be significantly less hedged than we have been in the past. Prices for natural gas and oil may fluctuate widely
in response to relatively minor changes in the supply of and demand for natural gas and oil, market uncertainty and a variety of additional factors that are beyond our control, such as:



| |  |  | the domestic and foreign supply of natural gas and oil;
| | - |  | -------------------------------------------------------



| |  |  | the price of foreign imports;
| | - |  | -----------------------------



| |  |  | overall domestic and global economic conditions;
| | - |  | ------------------------------------------------



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



| |  |  | weather conditions;
| | - |  | -------------------



| |  |  | technological advances affecting energy consumption;
| | - |  | ----------------------------------------------------



| |  |  | domestic and foreign governmental regulations;
| | - |  | ----------------------------------------------



| |  |  | proximity and capacity of oil and gas pipelines and other transportation facilities; and
| | - |  | ----------------------------------------------------------------------------------------



| |  |  | the price and availability of alternative fuels.
| | - |  | ------------------------------------------------



Many of these factors may be beyond our control. Because approximately 100% of our estimated proved reserves as of December 31, 2005 were natural gas
reserves, our financial results are more sensitive to movements in natural gas prices. Earlier in this decade, natural gas prices were much lower than they are today. Lower natural gas prices may not only decrease our revenues on a per unit basis,
but also may reduce the amount of natural gas that we can produce economically. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our estimates of development costs
increase, production data factors change or our exploration results deteriorate, accounting rules may require us to write down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are
required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carry amount may not be recoverable or
whenever managements plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken.



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



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



26



---

##### Table of Contents

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



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



| |  |  | geological conditions;
| | - |  | ----------------------



| |  |  | changes in governmental regulations and taxation;
| | - |  | -------------------------------------------------



| |  |  | assumptions governing future prices;
| | - |  | ------------------------------------



| |  |  | the amount and timing of actual production;
| | - |  | -------------------------------------------



| |  |  | future operating costs; and
| | - |  | ---------------------------



| |  |  | capital costs of drilling new wells.
| | - |  | ------------------------------------



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



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



Producing natural gas reservoirs generally are characterized by declining
production rates that vary depending upon reservoir characteristics and other factors. Because total estimated proved reserves include our proved undeveloped reserves at December 31, 2005, production is expected to decline even if those proved
undeveloped reserves are developed and the wells produce as expected. The rate of decline will change if production from our existing wells declines in a different manner than we have estimated and can change under other circumstances. Thus, our
future natural gas reserves and production and, therefore, our cash flow and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable
reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.



Our exploration and development activities may not be commercially successful.



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



| |  |  | unexpected drilling conditions;
| | - |  | -------------------------------



| |  |  | title problems;
| | - |  | ---------------



27



---

##### Table of Contents

| |  |  | pressure or irregularities in geologic formations;
| | - |  | --------------------------------------------------



| |  |  | equipment failures or repairs;
| | - |  | ------------------------------



| |  |  | fires or other accidents;
| | - |  | -------------------------



| |  |  | adverse weather conditions;
| | - |  | ---------------------------



| |  |  | reductions in natural gas and oil prices;
| | - |  | -----------------------------------------



| |  |  | pipeline ruptures; and
| | - |  | ----------------------



| |  |  | unavailability or high cost of drilling rigs, other field services and equipment.
| | - |  | ---------------------------------------------------------------------------------



Our future drilling activities may not be successful, and our drilling success rates could decline. Unsuccessful drilling
activities could result in higher costs without any corresponding revenues.



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



We transport our gas to market by utilizing pipelines owned by others. If
pipelines do not exist near our producing wells, if pipeline capacity is limited or if pipeline capacity is unexpectedly disrupted, our gas sales could be limited, and our transportation costs could increase, reducing our profitability. If we cannot
access pipeline transportation, we may have to reduce our production of gas or vent our produced gas to the atmosphere because we do not have facilities to store excess inventory. In the current year, we have had to shut-in production due to
shipping capacity limitations on Columbias KA-20 line that transports most of our Virginia gas to market and to compete with other producers for a portion of the pipeline capacity by purchasing firm transportation capacity that added to our
cost. Although we have reached an agreement with ETNG, to gain access to its pipeline, we may not be able to successfully gain access to that pipeline. If our sales are reduced because of transportation constraints, our revenues will be reduced,
which will also increase our costs. If we are not successful with our bid for transportation capacity and we do not have the ability to store gas, we may have to reduce production.



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



The gas industry is intensely competitive and we compete with companies from
various regions of the United States and may compete with foreign companies for domestic sales, many of whom are larger and have greater financial, technological, human and other resources. If we are unable to compete, our company, its operating
results and financial position may be adversely affected. For example, one of our competitive strengths is as a low-cost producer of gas. If our competitors can produce gas at a lower cost than us, it would effectively eliminate our competitive
strength in that area.



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



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



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



28



---

##### Table of Contents

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



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



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



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



Government laws, regulations and other legal requirements relating to protection of the environment, health and safety matters and others that govern our and CONSOL
Energys businesses increase our costs and may restrict our operations.



We and our principal stockholder, CONSOL Energy, are subject to laws, regulations and other legal requirements enacted or adopted by federal, state and local, as well as foreign authorities relating to protection of
the environment and health and safety matters, including those legal requirements that govern discharges of substances into the air and water, the management and disposal of hazardous substances and wastes, the clean-up of contaminated sites,
groundwater quality and availability, plant and wildlife protection, reclamation and restoration of mining or drilling properties after mining or drilling is completed, control of surface subsidence from underground mining and work practices related
to employee health and safety. Complying with these requirements, including the terms of our and CONSOL Energys permits, has had, and will continue to have, a significant effect on our respective costs of operations and competitive position.
In addition, we could incur substantial costs, including clean-up costs, fines and civil or criminal sanctions and third party damage claims for personal injury, property damage, wrongful death, or exposure to hazardous substances, as a result of
violations of or liabilities under environmental and health and safety laws. Moreover, given our relationship with CONSOL Energy, its compliance with these laws and regulations could impact our ability to effectively produce gas from our wells.



29



---

##### Table of Contents

Additionally, the gas industry is subject to extensive legislation and regulation, which is under
constant review for amendment or expansion. Any changes may affect, among other things, the pricing or marketing of gas production. State and local authorities regulate various aspects of gas drilling and production activities, including the
drilling of wells (through permit and bonding requirements), the spacing of wells, the unitization or pooling of gas properties, environmental matters, safety standards, market sharing and well site restoration. If we fail to comply with statutes
and regulations, we may be subject to substantial penalties, which would decrease our profitability.



We must obtain governmental permits and approvals for drilling operations, which can be a costly and time consuming process and result in restrictions on our operations.



Regulatory authorities exercise considerable discretion in the timing and
scope of permit issuance. Requirements imposed by these authorities may be costly and time consuming and may result in delays in the commencement or continuation of our exploration or production operations. For example, we are often required to
prepare and present to federal, state or local authorities data pertaining to the effect or impact that proposed exploration for or production of gas may have on the environment. Further, the public may comment on and otherwise engage in the
permitting process, including through intervention in the courts. Accordingly, the permits we need may not be issued, or if issued, may not be issued in a timely fashion, or may involve requirements that restrict our ability to conduct our
operations or to do so profitably.



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



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



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



We need to use unproven technologies to extract coalbed methane on some of our properties.



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



30



---

##### Table of Contents

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



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



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



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



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



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



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



31



---

##### Table of Contents

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



32



---

##### Table of Contents

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



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



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



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



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



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



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



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



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



33



---

##### Table of Contents

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



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



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



ITEM 2. PROPERTIES



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



ITEM 3. LEGAL PROCEEDINGS



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



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



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



34



---

##### Table of Contents

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



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



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



None.



35



---

##### Table of Contents

PART II



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



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



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



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



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



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



Recent Sales of Unregistered Securities



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



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



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



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



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



36



---

##### Table of Contents

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



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



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



37



---

##### Table of Contents

ITEM 6. SELECTED FINANCIAL DATA



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



CNX GAS CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME



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



38



---

##### Table of Contents

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

---

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

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

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

|(4) | EBIT is defined as earnings before deducting net interest expense (interest expense less interest income) and income taxes. EBITDA is defined as earnings before
deducting net interest expense (interest expense less interest income), income taxes and depreciation, depletion and amortization. Although EBIT and EBITDA are not measures of performance calculated in accordance with accounting principles generally
accepted in the United States of America, management believes that they are useful to an investor in evaluating CNX Gas because they are used as measures to evaluate a companys operating performance before debt expense and cash flow. EBIT and
EBITDA do not purport to represent cash generated by operating activities and should not be considered in isolation or as substitute for measures of performance in accordance with accounting principles generally accepted in the United States of
America. In addition, because EBIT and EBITDA are not calculated identically by all companies, the presentation here may not be comparable to
|--- | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



39



---

##### Table of Contents

| | other similarly titled measures of other companies. Managements discretionary use of funds depicted by EBIT and EBITDA may be limited by working
capital, debt service and capital expenditure requirements, and by restrictions related to legal requirements, commitments and uncertainties. A reconciliation of EBIT and EBITDA to financial net income is as follows:
| | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------



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



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



40



---

##### Table of Contents

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



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



Overview



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



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



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



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



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



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



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



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



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



| |  |  | generated net income in excess of $100 million;
| | - |  | -----------------------------------------------



| |  |  | increased our proved reserve base by replacing 271 percent of our 2005 production;
| | - |  | ----------------------------------------------------------------------------------



| |  |  | worked another year without a lost time accident; and
| | - |  | -----------------------------------------------------



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



41



---

##### Table of Contents

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



Results of
Operations



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

(Amounts reported in thousands)



Net Income



Net income changed primarily due to the following items:



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



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



Revenue and Other Income



Revenue and other income increased due to the following items:



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



42



---

##### Table of Contents

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



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



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



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



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



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



43



---

##### Table of Contents

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



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



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



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



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



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



Costs and Expenses



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



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



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



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



44



---

##### Table of Contents

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



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



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



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



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



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



Other costs and
expenses increased due to the following items:



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



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



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



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



45



---

##### Table of Contents

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



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



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



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



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



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



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



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



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



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



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



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



46



---

##### Table of Contents

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



Income Taxes



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



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



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



Net Income



Net income changed primarily due to the following items:



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



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



47



---

##### Table of Contents

Revenue and Other Income



Revenue and other income increased due to the following items:



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



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



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



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



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



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



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



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



48



---

##### Table of Contents

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



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



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



Costs and Expenses



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



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



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



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



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



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



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



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



49



---

##### Table of Contents

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



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



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



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



Other costs and
expenses decreased due to the following items:



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



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



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



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



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



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



50



---

##### Table of Contents

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



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



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



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



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



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



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



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



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



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



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



Income Taxes



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



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



51



---

##### Table of Contents

Cumulative Effect of Changes in Accounting for Gas Well Plugging Costs



Effective January 1, 2003, CNX Gas adopted SFAS No. 143 as
required. CONSOL Energy reflected a gain of $2,905, net of a tax cost of approximately $1,879. At the time of adoption, total assets, net of accumulated depreciation, increased approximately $2,085 and total liabilities decreased approximately
$2,699. The amounts recorded upon adoption are dependent upon a number of variables, including the estimated future retirement costs, estimated proved reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted
risk-free interest rate.



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



Critical Accounting Policies



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



Other Post Employment Benefits



CNX Gas
participates in certain CONSOL Energy sponsored benefit plans which provide medical and life benefits to employees that retire with at least twenty years of service and have attained age 55 or fifteen years of service and have attained age 62.
Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree medical and life benefits. In lieu of traditional retiree health coverage, if certain eligibility requirements
are met, these employees may be eligible to receive a retiree medical spending allowance of $1,000 per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which
covers eligible salaried employees and retirees. These changes include a cost sharing structure where essentially all participants contribute a minimum of 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan
participants. CNX Gas does not expect to contribute to the other post employment benefit plan in 2006. CNX Gas expects to pay benefit claims as they become due.



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



52



---

##### Table of Contents

Salaried Pensions



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



Reserve Estimates



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



Successful Efforts Accounting



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



Contingencies



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



Deferred Taxes



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



53



---

##### Table of Contents

million. The deferred tax asset components are evaluated periodically to determine if a valuation allowance is necessary. No valuation allowance has been
recognized because CNX Gas has determined that it is more likely than not that all of these deferred tax assets will be realized.



Well Plugging Obligations



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



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



Liquidity and Capital Resources



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



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



54



---

##### Table of Contents

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



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



Cash Flows



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



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



Contractual Commitments



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



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

---

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



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



55



---

##### Table of Contents

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



$200
Million Credit Facility.



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



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



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



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



| |  |  | create, incur, assume or suffer to exist any indebtedness;
| | - |  | ----------------------------------------------------------



| |  |  | create or permit to exist liens on its properties;
| | - |  | --------------------------------------------------



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



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



| |  |  | make particular investments and loans;
| | - |  | --------------------------------------



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



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



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



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



56



---

##### Table of Contents

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



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



| |  |  | voluntarily sell, pool or unitize its proved reserves.
| | - |  | ------------------------------------------------------



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



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



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



Off-Balance Sheet Arrangements



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



Recent Accounting Pronouncements



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



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



57



---

##### Table of Contents

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



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



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



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



58



---

##### Table of Contents

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



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



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



59



---

##### Table of Contents

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK



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



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



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



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



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



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



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

---

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



60



---

##### Table of Contents

Hedging Volumes



As of December 31, 2005, our hedged volumes for the periods indicated are as follows:



|                                 |  |                             |           |                           |   |                                |  |                               |           |            |   |           |  |   |           
|-------------------------------- |  | --------------------------- | --------- | ------------------------- | - | ------------------------------ |  | ----------------------------- | --------- | ---------- | - | --------- |  | - | ----------
|                                 |  | Three MonthsEnded March 31, |           | Three MonthsEndedJune 30, |   | Three MonthsEndedSeptember 30, |  | Three MonthsEndedDecember 31, |           | Total Year
|2006 Fixed Price Volumes         |  |                             |           |                           |   |                                |  |                               |           |            |   |           |  |   |           
|Hedged mcf                       |  |                             | 3,654,822 |                           |   | 4,619,289                      |  |                               | 4,670,051 |            |   | 4,050,761 |  |   | 16,994,923
|Weighted Average Hedge Price/mcf |  | $                           | 6.88      |                           | $ | 7.73                           |  | $                             | 7.73      |            | $ | 7.21      |  | $ | 7.42      
|                                 |  |                             |           |                           |  
|2007 Fixed Price Volumes         |  |                             |           |                           |   |                                |  |                               |           |            |   |           |  |   |           
|Hedged mcf                       |  |                             | 1,827,411 |                           |   | 1,847,717                      |  |                               | 1,868,020 |            |   | 1,868,020 |  |   | 7,411,168 
|Weighted Average Hedge Price/mcf |  | $                           | 7.67      |                           | $ | 7.67                           |  | $                             | 7.67      |            | $ | 7.67      |  | $ | 7.67      
|                                 |  |                             |           |                           |  
|2008 Fixed Price Volumes         |  |                             |           |                           |   |                                |  |                               |           |            |   |           |  |   |           
|Hedged mcf                       |  |                             | 1,847,716 |                           |   | 1,847,716                      |  |                               | 1,868,020 |            |   | 1,868,020 |  |   | 7,431,472 
|Weighted Average Hedge Price/mcf |  | $                           | 7.20      |                           | $ | 7.20                           |  | $                             | 7.20      |            | $ | 7.20      |  | $ | 7.20      



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



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



61



---

##### Table of Contents

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



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



62



---

##### Table of Contents

Report of Independent Registered Public Accounting Firm



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



In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, stockholders equity and cash flows present fairly, in all material respects, the financial position
of CNX Gas Corporation and its subsidiaries (CNX Gas) at December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting
principles generally accepted in the United States of America. These financial statements are the responsibility of CNX Gas management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted
our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.



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



/s/    PricewaterhouseCoopers LLP



Pittsburgh, Pennsylvania

February 20, 2006



63



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF INCOME

(Dollars in thousands, except per share data)



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



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



64



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)



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



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



65



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY

(Dollars in thousands)



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

---

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

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

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



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



66



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)



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



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



67



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS

(Dollars in thousands)



Note 1Significant Accounting Policies:



Nature of Operations



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



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



Basis of Consolidation



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



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



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



CNX Gas has no
variable interest entities.



Use of Estimates



The preparation of financial statements in conformity
with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and various disclosures. Actual
results could differ from those estimates. The most significant estimates included in the preparation of the financial statements are related to well plugging liabilities, proved gas reserve estimates, deferred tax assets and liabilities and
employee benefit related obligations.



Cash and Cash
Equivalents



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



68



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



Cash and cash equivalents include cash on hand and in banks as well as all highly liquid short-term securities with original maturities of three months or less.



Trade Accounts Receivable



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



Property, Plant and Equipment



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



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



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



Impairment of Long-Lived Assets



Impairment of long-lived assets, including investment in affiliates, is recorded when indicators of impairment are present
and the undiscounted cash flows estimated to be generated by those assets are less than the assets carrying value. The carrying value of the assets is then reduced to their estimated fair value which is usually measured based on an estimate of
future discounted cash flows. No adjustments were necessary during the periods presented.



Income Taxes



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



69



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



Pension Plan



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



Postretirement Benefits Other Than Pensions



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



Gas Well Plugging Costs



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



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



Revenue Recognition



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



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



70



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



Royalty Recognition



Royalty expenses for gas rights are included in cost of
goods sold and other charges when the related revenue for the gas sale is recognized. These royalty expenses are paid in cash in accordance with the terms of each agreement. Revenues for gas sold related to production under royalty contracts, versus
owned by CNX Gas, are recorded gross. The recognized revenues for these transactions are not net of related royalty fees.



Contingencies



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



Derivative Instruments



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



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



71



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



Stock Based Compensation



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



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



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



Earnings Per Share



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



72



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



73



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



Recent Accounting
Pronouncements



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



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



74



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



75



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



Reclassifications:



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



Note 2Transactions with Related Parties:



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



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



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



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



76



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



CONSOL Energy currently incurs
drilling costs related to gob gas production due to the necessity to de-gas coal mines prior to production for safety reasons. We estimate that the historical cost to CONSOL Energy of drilling these wells was as follows: $6,200 in 2005, $9,100 in
2004, and $9,300 in 2003. CNX Gas captures and markets the gas from these wells and, therefore, benefits from this drilling activity, although we are not burdened with the cost to drill gob wells. CNX Gas is responsible for the costs incurred to
gather and deliver the gob gas to market. All gob well drilling costs are borne by CONSOL Energy and only the collection and processing costs are reflected in CNX Gas historical financial statements. Our master cooperation and safety agreement
with CONSOL Energy retains this cost structure after our separation from CONSOL Energy.



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



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



Eligible employees may also participate in a long-term
disability plan administered by CONSOL Energy. Benefits for this plan are based on a percentage of monthly earnings, offset by all other income benefits available to the disabled. CNX Gas allocation of the long-term disability plan expense
under this plan was $228, $140 and $152 for the twelve months ended December 31, 2005, 2004 and 2003, respectively. Allocation of the expense for this plan is based on the percentage of CNX Gas active salary employees compared to the
total active salary employees covered by the plan.



CNX Gas is
insured for workers compensation claims in several states in which we operate and is self-insured for these claims in West Virginia and Virginia. Workers compensation expense for these benefits was



77



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



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



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



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



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



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



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



78



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



Note 3Other Income:



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



Note 4Income Taxes:



Income taxes provided on earnings consisted of:



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



79



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



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



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



80



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



Note 6Sales of Trade Accounts
Receivable:



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



Note 7Other Current Assets:



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



81



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



Note 8Property, Plant and Equipment:



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



Note 9Credit Facility:



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



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



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



82



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



Note 10Other Current Liabilities:



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



Note 11Leases:



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



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



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



Note 12Pension and Other Postemployment Benefits:



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



CNX Gas
participates in certain CONSOL Energy sponsored benefit plans which provides medical and life benefits to employees that retire with at least twenty years of service and have attained age 55 or fifteen years of service and have attained age 62.
Additionally, any salaried employees that are hired or rehired effective August 1, 2004 or later will not become eligible for retiree health benefits. In lieu of traditional retiree health



83



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



coverage, if certain eligibility requirements are met, these employees may be eligible to receive a retiree medical spending allowance of one thousand
dollars per year of service at retirement. In addition to the change in eligibility requirements, other changes have been made to the medical plan which covers eligible salaried employees and retirees. These changes include a cost sharing structure
where essentially all participants contribute 20% of plan costs. Annual cost increases in excess of 6% are paid entirely by the Plan participants. CNX Gas does not expect to contribute to the other postemployment benefit plan in 2006. CNX Gas
expects to pay benefit claims as they become due.



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



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



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



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



84



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



The components of net periodic benefit costs are as follows:



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



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



Assumptions:



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



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



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



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



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



The assumed health care cost trend rates are as follows:



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



85



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



Assumed health care cost trend rates have a significant effect on the amounts reported for the
medical plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:



|                                                         |  |                            |     |                            |   |      |  
|-------------------------------------------------------- |  | -------------------------- | --- | -------------------------- | - | ---- | -
|                                                         |  | 1-PercentagePoint Increase |     | 1-PercentagePoint Decrease |  
|Effect on total of service and interest costs components |  | $                          | 44  |                            | $ | (33  | )
|Effect on accumulated postemployment benefit obligation  |  |                            | 210 |                            |   | (283 | )



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



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



Cash Flows:



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



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



Note 13Stock-Based
Compensation:



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



The CNX Gas equity incentive plan consists of
the following components: stock options, stock appreciation rights, restricted stock units, performance awards, and other stock-based awards. The total number of shares of CNX Gas common stock with respect to which awards may be granted under CNX
Gas plan is 2,500,000. As of December, 31, 2005 our board has granted 92,969 shares of common stock underlying restricted stock units and 1,041,026 shares of common stock underlying stock options to officers, directors and employees of CNX
Gas.



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



86



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



At December 31,
2005 there were no exercisable options.



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



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



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



87



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



Note 14Other Comprehensive Loss:



Accumulated other comprehensive loss consists entirely of the following:



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



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



Note 15Supplemental Cash
Flow Information:



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



Note 16Concentration of
Credit Risk:



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



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



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



88



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



Note 17Derivative Instruments:



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



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



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



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



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



Note 18Commitments and Contingent Liabilities:



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



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



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



89



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



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



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



90



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



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



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



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



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



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



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



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



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



91



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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



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



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



Note 19Segment Information:



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



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



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

---

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

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



92



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



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

---

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

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



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



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

---

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



93



---

##### Table of Contents

CNX GAS CORPORATION AND SUBSIDIARIES



NOTES TO AUDITED FINANCIAL STATEMENTS(Continued)

(Dollars in thousands)



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



Note
20Subsequent Event



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



94



---

##### Table of Contents

Other Supplemental InformationSupplemental Gas Data (unaudited):



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



Capitalized Costs:



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

---

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



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



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



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

---

|(*) | Includes costs incurred whether capitalized or expensed
|--- | -------------------------------------------------------



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



95



---

##### Table of Contents

Results of Operations:



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

---

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

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



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



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



96



---

##### Table of Contents

Standardized Measure of Discounted Future Net Cash Flows:



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



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



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



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



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



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



97



---

##### Table of Contents

Other Supplemental InformationSelected Quarterly Data (Unaudited):



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



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



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



None.



ITEM 9A. CONTROLS AND PROCEDURES



Evaluation of Disclosure Controls and Procedures



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



98



---

##### Table of Contents

Changes in Internal Controls Over Financial Reporting.



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



ITEM 9B. OTHER INFORMATION



None



99



---

##### Table of Contents

PART III



ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT



The information required by this Item is incorporated herein by reference to the information under the captions Proposal #1Nominations for Election of Directors, General InformationThe
Board of Directors and Its CommitteesThe Board of Directors, General InformationThe Board of Directors and Its CommitteesMembership and Meetings of the Board of Directors and Its Committees and Section 16(a)
Beneficial Ownership Reporting Compliance in the Proxy Statement for the annual meeting of shareholders to be held on April 28, 2006 (the Proxy Statement).



Executive Officers of CNX Gas Corporation



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



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



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



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



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



100



---

##### Table of Contents

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



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



ITEM 11. EXECUTIVE COMPENSATION.



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



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



The information requested by this Item is incorporated by reference to the information under the captions Executive Compensation and Stock Option
InformationCNX Gas Stock Options Grants, Executive Compensation and Stock Option InformationCONSOL Energy Stock Option Grants and General InformationBeneficial Ownership of Securities in the Proxy
Statement.



ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.



The information requested by this Item is incorporated by reference to the information under the caption Executive Compensation and Stock Option InformationRelated Party Transactions in the Proxy
Statement.



ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.



The information required by this Item is incorporated by reference to the information in the table found in the section captioned Accountants and Audit Committee and the information under the caption
Accountants and Audit CommitteeAudit Committee Pre-Approval of Audit and Permissible Non-audit Services in the Proxy Statement.



101



---

##### Table of Contents

PART IV



ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.



|               |  |                                                                                                                      
|-------------- |  | ---------------------------------------------------------------------------------------------------------------------
|(a)(1)         |  | Financial Statements:                                                                                                
|               | 
|               |  | The financial statements included in Part II, Item 8 above are filed as part of this annual report.                  
|               | 
|(a)(2)         |  | Financial Statement Schedules:                                                                                       
|               | 
|               |  | No schedules are required to be presented by CNX.                                                                    
|               | 
|(a)(3) and (b) |  | Exhibits:                                                                                                            
|               | 
|               |  | The exhibits listed on the Exhibit Index which follows the Signatures hereto are filed as part of this annual report.



102



---

##### Table of Contents

SIGNATURES



Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, as of the 21st day of February, 2006.



CNX Gas CorporationBy:

/S/    NICHOLAS J.
DEIULIISNicholas J. DeIuliis President and Chief Executive Officer




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



|                                                    |  |                                                                              
|--------------------------------------------------- |  | -----------------------------------------------------------------------------
|Signature                                           |  | Title                                                                        
|                                                    | 
|/S/    PHILIP W.
BAXTERPhilip W.
Baxter             |  | Chairman of the Board                                                        
|                                                    | 
|/S/    NICHOLAS J.
DEIULIISNicholas J.
DeIuliis     |  | President, Chief Executive Officer and Director (Principal Executive Officer)
|                                                    | 
|/S/    GARY J.
BENCHGary J.
Bench                   |  | Chief Financial Officer (Principal Financial and Accounting Officer)         
|                                                    | 
|/S/    J. BRETT
HARVEYJ. Brett
Harvey               |  | Director                                                                     
|                                                    | 
|/S/    JAMES E. ALTMEYER,
SR.James E. Altmeyer,
Sr. |  | Director                                                                     
|                                                    | 
|/S/    RAJ K.
GUPTARaj K. Gupta                     |  | Director                                                                     
|                                                    | 
|/S/    JOHN R.
PIPSKIJohn R.
Pipski                 |  | Director                                                                     
|                                                    | 
|/S/    WILLIAM J.
LYONSWilliam J.
Lyons             |  | Director                                                                     



103



---

##### Table of Contents

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)                          



---

##### Table of Contents

|      |  |                                                                                                                                                                                                      
|----- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.20 |  | Supplemental Indenture No. 4, dated as of August 8, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New York,
as trustee(3)  
|      | 
|10.21 |  | Supplemental Indenture No. 5, dated as of October 21, 2005, among CONSOL Energy Inc., certain subsidiaries of CONSOL Energy Inc. and The Bank of Nova Scotia Trust Company of New
York, as trustee(9)
|      | 
|10.22 |  | Precedent Agreement dated July 29, 2005 by and between East Tennessee Natural Gas, LLC and CNX Gas Company, LLC.(10)                                                                                 
|      | 
|10.23 |  | Description of the CNX Gas Corporation 2006 Short-Term Incentive Compensation Program(11)*                                                                                                           
|      | 
|21    |  | Subsidiaries of CNX Gas Corporation(1)                                                                                                                                                               
|      | 
|23.1  |  | Consent of PricewaterhouseCoopers LLP                                                                                                                                                                
|      | 
|23.2  |  | Consent of Ralph E. Davis Associates, Inc.                                                                                                                                                           
|      | 
|23.3  |  | Consent of Schlumberger Data and Consulting Services                                                                                                                                                 
|      | 
|31.1  |  | Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                   
|      | 
|31.2  |  | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002                                                                                                   
|      | 
|32.1  |  | Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                    
|      | 
|32.2  |  | Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002                                                    

---

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

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

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

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

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

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

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

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

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

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

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



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



|* | Management compensatory contract or arrangement.
|- | ------------------------------------------------