Penn Virginia Corporation Reports a 35 Percent Increase in Proved Reserves and a 15 Percent Increase in Annual Production

Records for Annual and Quarterly Production and Proved Reserves; 604 Percent Reserve Replacement at a Drillbit Cost of $1.94 Per Mcfe; Fourth Quarter Production 13 Percent Higher Than Previous Quarter

RADNOR, Pa.-- Penn Virginia Corporation (NYSE:PVA) today announced record levels of proved oil and gas reserves and production and provided an update of its oil and gas operations, including full-year and fourth quarter 2008 results.

Full-Year and Fourth Quarter 2008 Highlights

Operational results for our oil and gas segment for the year ended December 31, 2008 included the following:

    --  Record year-end proved oil and gas reserves of 916 billion cubic feet of
        natural gas equivalent (Bcfe), an increase of 35 percent over 680 Bcfe
        at year-end 2007;
    --  Record oil and gas production of 46.9 Bcfe, or 128.1 million cubic feet
        of natural gas equivalent (MMcfe) per day, an increase of 15 percent
        over 40.6 Bcfe, or 111.1 MMcfe per day, in 2007;
    --  Reserve replacement ratio of 604 percent at a reserve replacement cost
        of $2.27 per thousand cubic feet of natural gas equivalent (Mcfe) and a
        drillbit reserve replacement cost, which excludes leasehold acquisition
        costs, of $1.94 per Mcfe;
    --  Oil and gas capital expenditures of approximately $642 million,
        including approximately $505 million for drilling and completion
        activities; and
    --  282 (176.4 net) wells drilled, with a 97 percent success rate.

Operational results for our oil and gas segment during the fourth quarter of 2008 included the following:

    --  Quarterly record oil and gas production of 13.2 Bcfe, or 143.8 MMcfe per
        day, representing production growth of 24 percent from 10.7 Bcfe, or
        116.1 MMcfe per day, in the fourth quarter of 2007 (13 percent higher as
        compared to the previous quarterly record of 11.7 Bcfe produced in the
        third quarter of 2008);
    --  Oil and gas capital expenditures of approximately $185 million,
        including approximately $165 million for drilling and completion
        activities;
    --  110 (60.2 net) wells drilled, with a 99 percent success rate; and
    --  Continued horizontal drilling success in the Lower Bossier (Haynesville)
        Shale in East Texas, the Granite Wash in the Mid-Continent region and
        the Selma Chalk in Mississippi.

2009 Guidance Update

Full-year 2009 guidance updates are as follows:

    --  Production guidance of 51.0 to 53.0 Bcfe, or 139.7 to 145.2 MMcfe per
        day, as compared to a range of 52.0 to 54.0 Bcfe of previous guidance;
        and
    --  Oil and gas capital expenditures guidance of $225 to $250 million, as
        compared to the 2009 capital budget of $250 million.

Management Comment

A. James Dearlove, President and Chief Executive Officer, said, "We are pleased with our record fourth quarter and annual proved reserves and production. We achieved these results in spite of ongoing disruptions in the financial and commodities markets, volume curtailments due to inclement weather and other operational issues, as well as shifts in operational focus to relatively new plays or development approaches using horizontal drilling in several of our major operating areas.

"Given ongoing market conditions and lower commodity prices, we believe it remains prudent to plan 2009 capital expenditures such that we can remain generally cash flow neutral and within expected liquidity levels. Should the financial markets and commodity prices improve, we will consider increasing the level of capital expenditures as appropriate.

"We have an ample multi-year inventory of high-quality drilling projects. Our horizontal drilling success and increased production in the Lower Bossier Shale, Granite Wash and Selma Chalk plays during 2008 have positioned us for year-over-year reserve and production growth in those plays, in spite of our reduced capital expenditures forecast."

Proved Reserves

Proved reserves increased 35 percent to a record 916 Bcfe at year-end 2008 from 680 Bcfe at year-end 2007. Natural gas comprised approximately 82 percent of year-end proved reserves and 51 percent was attributable to proved developed wells. Estimated proved reserves included:

    --  419 Bcfe in East Texas, including 68 Bcfe for the Lower Bossier
        (Haynesville) Shale;
    --  170 Bcfe in Appalachia;
    --  155 Bcfe in Mississippi;
    --  141 Bcfe in the Mid-Continent region, including 76 Bcfe for the Granite
        Wash; and
    --  31 Bcfe in the Gulf Coast of south Louisiana and south Texas.

We replaced 604 percent of our 2008 production entirely through the drillbit by adding approximately 283 Bcfe of proved reserves from extensions, discoveries and additions, net of revisions. Revisions were 51 Bcfe, primarily due to lower commodity prices at year-end 2008. Proved reserve additions included 156 Bcfe of increased proved developed (PD) reserves and 127 Bcfe of increased proved undeveloped (PUD) reserves, with no increases or decreases related to proved reserve acquisitions or divestitures. The increase in PD reserves was primarily attributable to development drilling success in East Texas, the Mid-Continent, Mississippi and Appalachia. The increase in PUD reserves was primarily attributable to success in the Lower Bossier Shale in 2008, as well as incremental reserves from the Cotton Valley and Granite Wash plays and royalty properties in Appalachia. Capital expenditures related to exploration and development, as well as leasehold acquisition, were $642 million, or $2.27 per Mcfe of proved reserves added. Excluding approximately $93 million of leasehold acquisition costs, our drillbit reserve replacement cost in 2008 was $1.94 per Mcfe.

Production

Record full-year 2008 production of 46.9 Bcfe was 15 percent higher than in 2007 primarily due to initial development in the Lower Bossier Shale and increased Cotton Valley production in East Texas (where production was up 68 percent) and horizontal Granite Wash drilling success in the Mid-Continent region (up 85 percent). Production in the fourth quarter of 2008 was a quarterly record 13.2 Bcfe, or 143.8 MMcfe per day, an increase of 24 percent over the 10.7 Bcfe, or 116.1 MMcfe per day, in the fourth quarter of 2007, and a 13 percent sequential increase over the previous quarterly record of 11.7 Bcfe, or 127.1 MMcfe per day, set in the third quarter of 2008.

The year-over-year increase in quarterly production was primarily due to increased Lower Bossier Shale and Cotton Valley production in East Texas (where production was up 28 percent), horizontal Granite Wash drilling success in the Mid-Continent region (up 143 percent) and drilling success at Bayou Sale in south Louisiana in the Gulf Coast (up nine percent). The sequential increase in quarterly production was due to increases in the Mid-Continent region (up 82 percent), the Gulf Coast (up 26 percent) and Appalachia (up three percent). Mississippi production increased two percent sequentially, while East Texas production was down nine percent sequentially due to declines in Cotton Valley production as a result of reduced drilling and completion activity for that play in the second half of 2008, the delivery of approximately 0.3 Bcfe of produced natural gas liquids (NGLs) into storage facilities and complications associated with certain of the Lower Bossier Shale completions. We expect the stored NGLs to be sold during early 2009.

For full-year 2009, oil and gas production guidance has been lowered to a range of 51.0 to 53.0 Bcfe, or 139.7 to 145.2 MMcfe per day, an increase of nine to 13 percent over full-year 2008. This guidance compares to a previous guidance range of 52.0 to 54.0 Bcfe. The expected 4.1 to 6.1 Bcfe increase in 2009 production is primarily attributable to anticipated increases in the Lower Bossier Shale, the Granite Wash, south Louisiana and Mississippi, partially offset by anticipated decreases in the Cotton Valley, Appalachia, south Texas and horizontal coalbed methane (HCBM) in the Mid-Continent.

Capital Expenditures

During 2008, oil and gas capital expenditures were approximately $642 million, consisting of:

    --  $505 million to drill 282 (176.4 net) wells, including:


         $481 million to drill 271 (170.1 net) development wells with 256 (158.8
      -  net) successful wells, three (2.1 net) unsuccessful wells (a 98 percent
         success rate) and 12 (9.3 net) wells waiting on completion at year-end
         2008; and

         $24 million to drill 11 (6.3 net) exploratory wells with six (3.5 net)
      -  successful wells, three (1.3 net) unsuccessful wells (a 67 percent
         success rate) and two (1.5 net) wells under evaluation at year-end 2008



    --  $93 million for leasehold acquisition;
    --  $38 million for the expansion of gathering systems and other production
        facilities; and
    --  $6 million for the acquisition of seismic data and other geological and
        geophysical expenditures.

Due to continued deterioration in commodity prices resulting from economic weakness and uncertainty in the capital markets, expected 2009 oil and gas capital expenditures have been reduced from $250 million to a range of between $225 and $250 million. Our capital spending program is expected to be funded primarily by internally generated cash flows, including distributions received from Penn Virginia GP Holdings, L.P. (NYSE:PVG), which are currently an annualized $46 million based on PVG's latest declared distribution. Borrowings under our revolving credit facility were $332 million at December 31, 2008, with remaining availability of approximately $147 million. Oil and gas capital expenditures in 2009 are subject to further revision as the operating environment and financial and capital market conditions change.

Operational Updates by Geographical Region

East Texas - During the fourth quarter of 2008, we drilled 17 (14.2 net) wells in East Texas, including four (4.0 net) Lower Bossier (Haynesville) Shale horizontal wells and 13 (10.2 net) Cotton Valley vertical wells. Of the wells drilled, eleven (8.7 net) wells were successful, including three (3.0 net) Lower Bossier Shale wells and eight (5.7 net) Cotton Valley wells, and six (5.5 net) wells were waiting on completion, including one (1.0 net) Lower Bossier Shale well and five (4.5 net) Cotton Valley wells.

East Texas production in the fourth quarter averaged 37.2 MMcfe per day, 28 percent higher than the 29.1 MMcfe per day produced in the fourth quarter of 2007 and nine percent lower than the 40.9 MMcfe per day produced in the third quarter of 2008. Cotton Valley production in East Texas decreased 0.8 Bcfe (or 8.2 MMcfe per day) during the fourth quarter of 2008 as compared to the prior quarter due to natural declines in production related to a reduced level of drilling and completion activity for that play during the second half of 2008 (approximately 0.5 Bcfe) and NGLs that were delivered into storage pending expected sale in 2009 (approximately 0.3 Bcfe). Offsetting the decrease in Cotton Valley production was a 0.4 Bcfe (or 4.6 MMcfe per day) increase in Lower Bossier production during the fourth quarter of 2008 as compared to the prior quarter as a result of an increased level of drilling in that play during the second half of 2008.

To date, we have drilled 13 Lower Bossier Shale wells, with eight producing wells and five wells waiting on completion. Early results for the six wells for which such data is available include an average 30-day restricted gross production rate of 3.5 MMcfe per day, with an average flowing tubing pressure (FTP) of 2,800 pounds per square inch (psi). The range of 30-day rates for these six wells was between 1.1 MMcfe per day for the Brown #8-H, which had mechanical problems that caused only two of the eight proposed frac stages to be completed, to 5.9 MMcfe per day for the Fogle #5-H, which was the discovery well. Maximum one-day rates for the producing wells averaged approximately 5.3 MMcfe per day, with an average FTP of 4,100 psi. The range of one-day rates for these wells was between 2.0 MMcfe for the Brown #8-H and 8.8 MMcfe for the Fogle #5-H.

To obtain additional formation data, we are currently drilling a well that is expected to be cored from the base of the Cotton Valley down through the Haynesville Lime, which lies immediately below the Lower Bossier Shale. We expect the interpretation of this core data to enhance our drilling and completion designs for horizontal Lower Bossier Shale wells. In addition, we expect this core data to be helpful in the drilling and completion design for horizontal wells in the Upper Bossier Shale, which we believe has significant potential.

Estimated gross reserves for Lower Bossier Shale PUD wells were approximately 5.0 Bcfe per well at year-end 2008. Based on early results in the play, we expect to continue development drilling in 2009 and beyond. We currently have two operated rigs drilling Lower Bossier Shale wells and anticipate drilling up to 12 (8.4 net) wells during 2009, one of which may be a horizontal Cotton Valley well.

Mid-Continent - During the fourth quarter of 2008, we drilled 25 (11.6 net) wells in the Mid-Continent region, including six (3.0 net) Granite Wash horizontal wells, seven (5.8 net) Hartshorne HCBM wells, nine (1.0 net) Woodford Shale horizontal wells, two (1.4 net) Fayetteville Shale horizontal wells and one (0.3 net) conventional vertical well. Of the wells drilled, 22 (10.3 net) wells were successful and three (1.3 net) wells were under evaluation at year-end, including one (1.0 net) Hartshorne HCBM well and two (0.3 net) Woodford Shale wells.

Mid-Continent production in the fourth quarter averaged 31.8 MMcfe per day, 143 percent higher than the 13.1 MMcfe per day produced in the fourth quarter of 2007 and 82 percent higher than the 17.5 MMcfe per day produced in the third quarter of 2008. The sequential quarterly increase was due to production increases in all play types, including the horizontal Granite Wash play (up 392 percent), the Woodford Shale (up 80 percent), the Hartshorne HCBM (up 11 percent) and conventional / other production (up 27 percent).

Well results in the Granite Wash continued to be strong with an average 30-day restricted gross rate of 7.9 MMcfe per day for the 12 wells for which such data is available. Estimated gross reserves for Granite Wash PUD wells were approximately 6.0 Bcfe per well at year-end 2008. We currently have one operated rig and two non-operated rigs drilling Granite Wash wells and anticipate drilling up to 12 (6.4 net) wells in 2009.

Mississippi - During the fourth quarter of 2008, we drilled 10 (9.9 net) Selma Chalk wells in Mississippi, including seven (6.9 net) horizontal wells and three (3.0 net) vertical wells. Of the wells drilled, nine (8.9 net) wells were successful and one (1.0 net) vertical well was unsuccessful.

Mississippi production in the fourth quarter averaged 20.4 MMcfe per day, flat as compared to the 20.5 MMcfe per day produced in the fourth quarter of 2007 and two percent higher than the 20.0 MMcfe per day produced in the third quarter of 2008. The flat production profile in Mississippi is due to natural declines in production from a large number of older vertical wells and decreased drilling activity that is being offset by new production from a smaller number of more recently drilled horizontal wells.

Horizontal well results for the Selma Chalk continue to be encouraging with an average 30-day restricted gross rate of 0.8 MMcfe per day, with an average FTP of 1,300 psi, for the 13 wells for which such data is available. Estimated gross reserves for Selma Chalk PUD wells were approximately 1.5 Bcfe per well at year-end 2008. We currently have one operated rig drilling Selma Chalk horizontal wells and anticipate drilling up to 22 (21.4 net) wells in 2009.

Appalachia - During the fourth quarter of 2008, we drilled 55 (21.9 net) wells in Appalachia, including three (1.2 net) multi-lateral HCBM wells, 51 (19.6 net) non-operated vertical coalbed methane (CBM) wells and one (1.0 net) Lower Huron Shale horizontal well. Of the wells drilled, 54 (20.9 net) wells were successful and the Lower Huron Shale exploratory well was under evaluation at year-end.

Appalachian production in the fourth quarter averaged 31.8 MMcfe per day, three percent lower than the 32.6 MMcfe per day produced in the fourth quarter of 2007 and three percent higher than the 30.8 MMcfe per day produced in the third quarter of 2008. The flat production profile in Appalachia is due to natural declines in production from a large number of older, vertical conventional and CBM wells that is being offset by new production from a relatively small number of HCBM wells. The large number of non-operated vertical CBM wells drilled in the fourth quarter of 2008 relates to our participation in a drilling program in southwestern Virginia.

We currently have one HCBM rig drilling in Appalachia and anticipate drilling up to two (1.5 net) exploratory Marcellus Shale wells in Pennsylvania in 2009.

Gulf Coast - During the fourth quarter of 2008, we drilled two (1.7 net) development wells in the Gulf Coast region, both of which were successful and both of which were located in south Texas.

Gulf Coast production in the fourth quarter averaged 22.6 MMcfe per day, nine percent higher than the 20.8 MMcfe per day produced in the fourth quarter of 2007 and 26 percent higher than the 17.9 MMcfe per day produced in the third quarter of 2008. These increases were primarily due to production increases in south Louisiana (up 17 percent from the prior year quarter and up 54 percent from the prior quarter), offset in part by production declines in south Texas (a decrease of nine percent from the prior year quarter and a decrease of 17 percent from the prior quarter). The increases in south Louisiana were due to successful drilling in 2007 at Bayou Sale and in 2008 at Bayou Postillion, while the decreases in south Texas related to natural production declines and a reduced level of drilling activity.

We anticipate drilling one (0.3 net) exploratory well in south Louisiana 2009.

Derivative Update

To support the operating cash flows that underpin our 2009 oil and gas capital expenditures, we hedge our natural gas and oil production at pre-determined prices or price ranges. Based on derivatives currently in place for 2009, as detailed in the table below, we have hedged approximately 42 million cubic feet of natural gas production per day and 500 barrels of crude oil production per day.


                                         Weighted Average

                                Average  Price per MMBtu or Bbl
                                Volume
                                Per Day  Additional  Floor     Ceiling
                                         Put Option

                                (MMBtu)

Natural Gas Three-Way Collars*

First quarter 2009              65,000   $ 6.00      $ 8.67    $ 11.68

Second quarter 2009             40,000   $ 6.00      $ 8.75    $ 10.79

Third quarter 2009              40,000   $ 6.00      $ 8.75    $ 10.79

Fourth quarter 2009             30,000   $ 6.00      $ 9.50    $ 13.60

First quarter 2010              30,000   $ 6.00      $ 9.50    $ 13.60

                                (Bbls)

Crude Oil Three-Way Collars*

First quarter 2009              500      $ 80.00     $ 110.00  $ 179.00

Second quarter 2009             500      $ 80.00     $ 110.00  $ 179.00

Third quarter 2009              500      $ 80.00     $ 110.00  $ 179.00

Fourth quarter 2009             500      $ 80.00     $ 110.00  $ 179.00




* A three-way collar is a combination of options: a sold call, a purchased put
and a sold put. The sold call (ceiling) establishes the maximum price that we
will receive for the contracted commodity volumes. The purchased put (floor)
establishes the minimum price that we will receive for the contracted volumes
unless the market price for the commodity falls below the sold (lower or
additional) put strike price, at which point the minimum price equals the
reference price (i.e., NYMEX) plus the excess of the purchased put strike price
over the sold put strike price.

Note: We estimate that, excluding the derivative positions described above, for
every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas
segment operating income for full-year 2009 would increase or decrease by
approximately $41 million. In addition, we estimate that for every $5.00 per
barrel increase or decrease in the oil price, oil and gas segment operating
income for full-year 2009 would increase or decrease by approximately $4
million. This assumes that crude oil prices, natural gas prices and production
volumes remain constant at forecasted levels. These estimated changes in
operating income exclude potential cash receipts or payments in settling these
derivative positions.



Full-Year and Fourth Quarter 2008 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss our fourth quarter 2008 financial and operational results, is scheduled for Thursday, February 12, 2009 at 3:00 p.m. ET. Prepared remarks by A. James Dearlove, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-877-407-9205 five to ten minutes before the scheduled start of the conference call, or via webcast by logging on to our website at www.pennvirginia.com at least 20 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay of the call will be available until February 26, 2009 at 11:59 p.m. ET by dialing 1-877-660-6853 and using the following replay pass codes: account #286, conference ID #309180. An on-demand replay of the conference call will be available at our website beginning shortly after the call.

Headquartered in Radnor, PA and a member of the S&P SmallCap 600 Index, Penn Virginia Corporation (NYSE:PVA) is an independent natural gas and oil company focused on the exploration, acquisition, development and production of reserves in onshore regions of the U.S., including the East Texas, Mississippi, the Mid-Continent region, the Appalachian Basin and the Gulf Coast of Louisiana and Texas. We also own approximately 77 percent of Penn Virginia GP Holdings, L.P. (NYSE:PVG), the owner of the general partner and the largest unit holder of Penn Virginia Resource Partners, L.P. (NYSE:PVR), a manager of coal and natural resource properties and related assets and the operator of a midstream natural gas gathering and processing business.

For more information, please visit our website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are "forward-looking" statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the volatility of commodity prices for natural gas, NGLs and crude oil; our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired; the relationship between natural gas, NGL and crude oil prices; the projected demand for and supply of natural gas, NGLs and crude oil; the availability and costs of required drilling rigs, production equipment and materials; our ability to obtain adequate pipeline transportation capacity for our oil and gas production; competition among producers in the oil and natural gas coal industry generally; the extent to which the amount and quality of actual production of our oil and natural gas differs from estimated proved oil and gas reserves; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our oil and natural gas production; environmental risks affecting the drilling and producing of oil and gas wells, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; uncertainties relating to the outcome of current and future litigation; risks and uncertainties relating to general domestic and international economic (including inflation, interest rates, and financial and credit markets) and political conditions (including the impact of potential terrorist attacks).

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2007. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management's views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as the result of new information, future events or otherwise.


    Source: Penn Virginia Corporation