CNX Gas Estimates Appalachian Recoverable Reserves and Net Unrisked Resource Potential of 3.6 Tcf to 7.4 Tcf; Proved Reserves Increase 6% to 1.3 Tcf; Company's First Conventional Gas Well in Pa. Achieves Open Flow of 1.2 MMcf Per Day

PITTSBURGH, Feb. 11 /PRNewswire-FirstCall/ -- CNX Gas Corporation (NYSE: CXG) estimates that it has recoverable reserves and net unrisked resource potential of 3.6 trillion cubic feet (Tcf) to 7.4 Tcf, in an updated review of its Appalachian coalbed methane (CBM) reserves and shale resources.

Nicholas J. DeIuliis, president and chief executive officer, said, "This updated assessment of our Appalachian recoverable reserves and resource potential shows the progress we have made. As recently as two-and-a-half years ago, we didn't fully appreciate the significance of our shale opportunities. Today, we estimate that our Appalachian shale resources alone could range from 1.3 to nearly 5.2 Tcf. When coupled with our CBM 3P reserves of nearly 2.3 Tcf, our total estimate for Appalachia now stands at 3.6 Tcf to over 7.4 Tcf. This range could be higher once we begin to analyze the Trenton Black River formation, the tight sands in our Virginia field, and our conventional oil and gas potential with a portion of our $88 million exploration program."

CNX Gas has proved reserves of 1,343 billion cubic feet (Bcf) as of December 31, 2007, or up 6% from the 1,265 Bcf reported at year-end 2006. Reserves are split nearly evenly between the proved developed and proved undeveloped categories. The proved developed category of 671 Bcf includes 619 Bcf of proved developed producing reserves. The proved reserve estimates for both 2006 and 2007 were prepared by Data & Consulting Services Division of Schlumberger Technology Corporation.

Dr. DeAnn Craig, senior vice president-asset assessment, commented on the proved reserves. "We are pleased to report a meaningful increase in our proved reserves, especially when one considers the drilling assistance we provided to CONSOL Energy to ensure the safety of Buchanan Mine. Some of our crews had to postpone well remediation efforts in 2007, which when completed in 2008, should help our year-end 2008 proved reserves. We also drilled 70 40-acre infill wells and 53 30-acre infills in Virginia in 2007, which helped production and returns, but did not add much to reserves."

The net increase in proved reserves of 78 Bcf, means that when coupled with 2007 production of 58 Bcf, the company replaced 234% of its production with a drill bit reserve replacement cost of $1.25 per Mcf. Drilling capital expenditures in 2007 were $170.5 million.

Dr. Craig continued, "As our Virginia CBM Operations continues to mature, I would expect more of our future reserve growth to be generated by our newer CBM plays, Mountaineer and Nittany, as well as from our exploratory plays. At expected drilling rates in Virginia, the probable reserves are expected to migrate into the proved category within five years. Furthermore in Virginia, the current non-mine-related proved undeveloped reserves (381 Bcf) are expected to be drilled within the next five years."

The probable category for Virginia CBM Operations includes estimates for horizontal wells in the eastern section of the Oakwood Field and for downspacing to 30-acre spacing on approximately 60,000 acres. The probable category does not include any estimate for downspacing to 20 acres, the viability of which the company is currently evaluating.

Proved reserves in Mountaineer CBM Operations increased from 33 Bcf in 2006 to 82 in 2007, as the company expanded its 2007 drilling to 62 wells, from only 15 wells in 2006. Nittany CBM Operations had no proved reserves in 2006.

    The following table shows the breakdown of reserves from the company's
current development plays, in Bcf.  Over 99 percent of the company's proved
reserves are gas:


                       Proved      Proved       Total                    Total
                      Developed  Undeveloped   Proved  Probable  Possible  3P
    Virginia
     Operations
     (CBM)                  617          621   1,238    411          0   1,649
    Mountaineer (CBM)        34           48      82    186        265     533
    Nittany (CBM)             2            3       5     40         39      84
     Total Appalachian
      CBM                   653          672   1,325    637        304   2,266
    Other                    18            0      18      0          0      18
     Total                  671          672   1,343    637        304   2,284

Definition: Total 3P is a summation of proved, probable and possible reserves.

The company has not included proved undeveloped reserves in the "other" category, which would include offsets to the horizontal Chattanooga Shale well that came on line in December 2007 and offsets to other producing wells.

Schlumberger calculated that the future net cash flows of the CNX Gas proved gas reserves have a present value of nearly $2.3 billion before income taxes, assuming a ten percent discount rate, as of December 31, 2007. This compares with a value of nearly $1.5 billion at December 31, 2006. The increase in value is largely driven by higher prices and a 6% increase in proved reserves. As is customary, the values assume flat pricing and constant unit costs. The average price used in the latest reserve study was $7.03, versus $5.61 per Mcf used in 2006. Both prices exclude the effects of hedged production.

CNX Gas has also estimated a range of net unrisked resource potential of the company's extensive Appalachian shale position.

                                                      Low        High
                                      Acres          (Bcf)       (Bcf)
    Chattanooga Shale                 132,000         206         825
    Huron Shale                       193,000         595       2,376
    Marcellus Shale                   161,000         515       1,964
     Total Appalachian Shale          486,000       1,316       5,165

This range of resource potential is based primarily on a variety of external sources. CNX Gas has drilled one horizontal well in the Chattanooga Shale, which had a test rate of 3.9 MMcf per day and sustained production of 300-400 Mcf per day.

When drilling the company's first vertical well to test the company's extensive Marcellus Shale acreage in southwestern Pennsylvania in January 2008, the rig encountered significant quantities of gas before reaching the Marcellus. Open flow testing for an 80-hour period yielded 1.2 MMcf per day. CNX Gas has completed the well at its current depth and placed it into production. CNX Gas will penetrate the Marcellus in 2008 at other locations.

The gas from this well and all other conventional gas locations in horizons other than the shales is not included in the above table of net unrisked resource potential. Gas from the Trenton Black River formation, which is thought to underlie nearly all of the company's 486,000 Appalachian shale acres, is also excluded from the current Appalachian assessment, as is any evaluation of tight sands potential in Virginia (on 134,000 acres) and conventional oil in Ohio (on 61,200 acres).

Additionally, CNX Gas holds 300,000 acres in the New Albany Shale. This acreage also has the potential for conventional oil. A further 573,000 acres of Illinois CBM continues to be evaluated, along with much of the company's western acreage. CNX Gas has, however, completed its initial evaluation of its Powder River Basin CBM acreage acquired in a transaction last June. Due to the location being outside of the company's core operating areas, CNX Gas will explore monetization via sale or swap of this asset, which is estimated by a consultant retained by the company to contain 300 Bcf of gas in place.

CNX GAS CORPORATION is an independent natural gas exploration, development, production and gathering company operating in the Appalachian and Illinois basins of the United States.

    Reconciliation of PV-10 to Standardized Measure (as of December 31)

                                   2007         2006         2005
    Future cash inflows        $ 9,509,665  $ 7,105,265  $11,675,551
    Future Production Costs    $(3,004,619) $(2,568,731) $(2,852,033)
    Future Development Costs   $  (636,436) $  (552,114) $  (422,315)
    Future net cash flows      $ 5,868,610  $ 3,984,420  $ 8,401,203
    10% discount factor        $(3,581,183) $(2,484,756) $(5,349,337)
    PV 10% (Non-GAAP measure)  $ 2,287,427  $ 1,499,664  $ 3,051,866

    Undiscounted Income Taxes  $(2,259,415) $(1,500,533) $(3,251,265)
    10% discount factor        $ 1,361,528  $   935,760  $ 2,070,193
    Discounted Income Taxes    $  (897,887) $  (564,773) $(1,181,072)
    Standardized GAAP measure  $ 1,389,540  $   934,891  $ 1,870,794

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

Various statements in this release, including those that express a belief, expectation, or intention, as well as those that are not statements of historical fact, are forward-looking statements (as defined in Section 21E of the Securities Exchange Act of 1934). These statements 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. 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; the availability of personnel and equipment; increased costs; the effects of government regulation and permitting and other legal requirements; legal uncertainties regarding the ownership of the coalbed methane estate; 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" in the 10-K for the year ended December 31, 2006. We are including this cautionary statement in this release 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.

CAUTIONARY STATEMENT CONCERNING 3P AND PROBABLE AND POSSIBLE RESERVES AND RESOURCES

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this presentation, such as "3P" and "probable" and "possible" reserves and/or "resource potential" that the SEC's guidelines strictly prohibit us from including in filings with the SEC. We also caution you that the SEC views such "3P" and "probable" and "possible" reserves and/or "resource potential" estimates as inherently unreliable and these estimates may be misleading to investors unless the investor is an expert in the gas industry.

The "3P" and "probable" and "possible" reserve data and/or "resource potential" contained in this release is based on a summary review of the title to coalbed methane and other gas rights we hold, as well as a summary review of the title to the coal from which many of our rights derive. As is customary in the gas industry, prior to the commencement of gas drilling operations on our properties, we conduct a thorough title examination and perform curative work with respect to significant defects. We are typically responsible for curing any title defects at our expense. This curative work may include the acquisition of additional property rights in order to perfect our ownership for development and production of the gas estate.

    Contact:
    Dan Zajdel
    Vice President - Investor and Public Relations
    (412) 200-6719
    danzajdel@cnxgas.comwww.cnxgas.com