Penn Virginia Corporation Announces Record Quarterly Oil Production and 2013 Oil Production Growth Guidance of 67 Percent

Penn Virginia Corporation Announces Record Quarterly Oil Production and 2013
Oil Production Growth Guidance of 67 Percent

         Core Eagle Ford Shale Position Expanded to 62,000 Net Acres

         Drilling Inventory Increased to Approximately 750 Locations

          Excellent Recent Drilling Results in the Eagle Ford Shale

              Financial Liquidity of Approximately $300 Million

RADNOR, Pa., Aug. 7, 2013 (GLOBE NEWSWIRE) -- Penn Virginia Corporation
(NYSE:PVA) today reported financial results for the three months ended June
30, 2013 and provided updates of its operations and 2013 guidance.

Second Quarter 2013 Highlights

Second quarter 2013 financial results, as compared to first quarter 2013
results, were as follows:

  *Product revenues from the sale of oil, natural gas liquids (NGLs) and
    natural gas were $109.7 million, or $62.78 per barrel of oil equivalent
    (BOE), an increase of 34 percent compared to $82.2 million, or $57.61 per
    BOE;
    
  *Oil and NGL revenues were $94.2 million, or 86 percent of product
    revenues, an increase of 34percent compared to $70.2million, or 85
    percent of product revenues;
    
  *Operating margin, a non-GAAP (generally accepted accounting principles)
    measure, excluding acquisition transaction expenses of $2.4million, was
    $46.09 per BOE, an increase of 20 percent compared to $38.55perBOE;
    
  *Operating income, also excluding acquisition transaction expenses, was
    $5.6million, compared to an operating loss of $3.0 million;
    
  *Adjusted EBITDAX, a non-GAAP measure, was $83.1 million, an increase of
    38percent compared to $60.3million;
    
  *Loss attributable to common shareholders (which includes our preferred
    stock dividend) was $27.2million, or $0.43 per diluted share, compared to
    a loss of $18.1million, or $0.33 per diluted share; and
    
  *Adjusted loss attributable to common shareholders (which includes our
    preferred stock dividend), a non-GAAP measure which excludes the effects
    of certain costs and other gains or losses that affect comparability to
    other periods, was $10.9million, or $0.17 per diluted share, compared to
    a loss of $10.4 million, or $0.19per diluted share.

Recent operational highlights were as follows:

  *Second quarter production of 1.7 million BOE (MMBOE), or 19,209 BOE per
    day (BOEPD), up 21 percent compared to 1.4 MMBOE, or 15,857BOEPD, in the
    first quarter.

    *Second quarter Eagle Ford Shale production of 11,476 BOEPD, up 53
      percent compared to 7,523BOEPD in the first quarter.

    *Record quarterly oil production of 9,430 barrels of oil per day (BOPD),
      an increase of 42 percent over 6,655 BOPD in the first quarter of 2013.

  *Including the Eagle Ford Shale assets acquired from Magnum Hunter
    Resources Corporation in April 2013 (MHR Acquisition), we currently have a
    total of 139(94.3net) Eagle Ford Shale producing wells, with 15 (8.4
    net) wells either completing or waiting on completion and five (2.1 net)
    wells being drilled.

    *The average peak gross production rate per well for the 120 (84.9 net)
      operated wells completed to date was 1,094BOEPD.The initial 30-day
      average gross production rate for the 116 of these 120 wells with a
      30‑day production history was 702BOEPD.The average lateral length for
      these operated wells was approximately 4,475 feet, with an average of 19
      fracturing (frac) stages.

    *The average peak gross production rate per well for the 22 (13.5 net)
      most recent operated wells was 1,282BOEPD.The initial 30-day average
      gross production rate for the 19 of these 22 wells with a 30-day
      production history was 787BOEPD.The average lateral length for these
      recent wells was approximately 5,520 feet, with an average of 22 frac
      stages.

  *The average stimulation (completion) cost per frac stage was approximately
    $150,000 in the second quarter of 2013, compared to approximately $200,000
    in the first quarter of 2013. This average is expected to decrease further
    to approximately $110,000 per frac stage beginning in the third quarter of
    2013, as we transition to new pumping service providers.
    
  *Currently, we have a total of approximately 110,000 gross (62,000 net)
    acres in the Eagle Ford Shale.

    *Approximately 9,000 net acres in the Eagle Ford Shale have been added
      recently at a cost of approximately $1,600 per acre; and

    *As previously announced in June 2013, approximately 1,300 net acres and
      associated production were divested pursuant to exercises of
      preferential rights in connection with the MHR Acquisition, with net
      proceeds to PVA of approximately $21.4 million before purchase price
      adjustments.

  *We estimate that we currently have approximately 750 undeveloped drilling
    locations, which is a drilling inventory of approximately 10 years,
    assuming an ongoing six-rig program.

    *This has increased from 645 locations that had been disclosed
      previously.

    *14 of our recently drilled wells were drilled off of six multi-well
      pads, with effective spacing of between 45 and 70 acres.

Definitions of non-GAAP financial measures and reconciliations of these
non-GAAP financial measures to GAAP-based measures appear later in this
release.Second quarter financial and production results reflect contributions
from the MHR acquisition from April 24, 2013 through June 30, 2013.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, "In the
second quarter, our operating cash flows and margins remained strong as a
result of the continued growth in oil production, including contributions from
the MHR Acquisition, as well as lower unit operating costs.We expect oil
production to increase by approximately 67 percent in 2013 over 2012,
comprising approximately 82percent of product revenues and approximately 53
percent of production.Substantial growth in oil production and cash flows is
expected to continue into 2014 and 2015.

"New leasing in the Eagle Ford Shale has materially increased our net acreage
at a cost of approximately $1,600 per net acre.As a result and in conjunction
with successful downspaced drilling, we have an approximate ten-year drilling
inventory at the current pace of drilling.We believe we will be able to
continue to add acreage at attractive costs, providing for further increases
to our drilling inventory.We expect to see significant reductions in our well
costs beginning in the second half of 2013 and expect that our overall Eagle
Ford Shale program will contribute substantial production and cash flow growth
over the next few years.Our balance sheet remains sound with approximately
$300 million of financial liquidity and a leverage ratio of approximately
3.5times net debt to pro forma Adjusted EBITDAX.We expect to fund our 2013
and 2014 capital programs with increasing operating cash flows and borrowings
under our revolver, decreasing our leverage ratio over time. We remain
excited about Penn Virginia's future with an ongoing six-rig program providing
estimated annual oil production growth of between 30 and 40 percent over the
next two years, with the expectation of self-funding our capital program by
the end of 2015 going into 2016."

Second Quarter 2013 Results

Overview of Financial Results

The $3.2 million operating income in the second quarter was a $6.2 million
improvement over the $3.0million loss in the first quarter, due primarily to
a $27.5million increase in total product revenues. The effect of this
increase was partially offset by a $4.3 million increase in total direct
operating expenses (including $2.4 million of acquisition transaction
expenses), a $12.7million increase in depreciation, depletion and
amortization (DD&A) expense, a $1.6 million increase in share-based
compensation expense, a $1.6million increase in exploration expense and a
$1.1 million decrease in other revenues.The changes in revenue and expense
items were attributable primarily to the MHR Acquisition in late April 2013.

Product Revenues

Total product revenues were $109.7 million in the second quarter, a 34 percent
increase compared to $82.2million in the first quarter, due primarily to
increased production, as well as a nine percent increase in average product
pricing from $57.61 per BOE to $62.78 per BOE.Oil and NGL revenues were
$94.2million in the second quarter, a 34 percent increase compared to
$70.2million in the first quarter, due primarily to increased production.Oil
and NGL revenues were 86percent of product revenues in the second quarter,
compared to 85 percent in the first quarter.

Operating Expenses

As discussed below, second quarter total direct operating expenses, excluding
$2.4 million of acquisition transaction expenses, increased $2.0 million to
$29.2million, or $16.68per BOE produced, compared to $27.2 million, or
$19.06 per BOE produced, in the first quarter.

  *Lease operating expenses increased by $0.8 million to $8.6 million, or
    $4.94per BOE, from $7.8million, or $5.47 per BOE, due to higher
    production;
    
  *Gathering, processing and transportation expenses decreased by $0.6
    million to $3.0million, or $1.70 per BOE, from $3.6 million, or $2.51 per
    BOE, due primarily to certain non-recurring charges recorded during the
    first quarter;
    
  *Production and ad valorem taxes increased by $1.0 million to $7.0million,
    or 6.4 percent of product revenues, from $6.0million, or 7.2 percent of
    product revenues, due primarily to production increases in the Eagle Ford
    Shale; and
    
  *General and administrative expenses, excluding share-based compensation
    and acquisition transaction expenses, increased by $0.7million to
    $10.6million, or $6.05 per BOE, from $9.9 million, or $6.91 per BOE, due
    primarily to higher employee-related costs in the second quarter, as well
    as transition services related to the MHR Acquisition.

Exploration expense increased by $1.6 million to $7.8million in the second
quarter from $6.2million in the first quarter.The increase was due primarily
to the cost of seismic data acquired in connection with the MHR Acquisition.

DD&A expense increased by $12.7 million to $64.3million, or $36.80 per BOE
produced, in the second quarter of 2013 from $51.6 million, or $36.14 per BOE
produced, in the first quarter due primarily to production increases in the
Eagle Ford Shale.

Second Quarter 2013 Operational Results

Production

Production in the second quarter was 1.7MMBOE, or 19,209 BOEPD, compared to
1.4 MMBOE, or 15,857BOEPD, in the first quarter.As a percentage of total
equivalent production, oil and NGL volumes were 64percent in the second
quarter of 2013, compared to 58 percent in the first quarter.The table below
shows quarterly production detail.

                   Total and Daily Equivalent Production for the Three Months
                    Ended
Region / Play Type  June 30,  March 31, June 30, June 30,  March 31, June 30,
                    2013      2013      2012     2013      2013      2012
                   (in MBOE)                    (in BOEPD)
Texas               1,304     954       935      14,331    10,599    10,271
Eagle Ford         1,044     677       596      11,476    7,523     6,553
Cotton Valley      184       195       215      2,025     2,169     2,364
Haynesville Shale  71        82        123      780       906       1,355
Mid-Continent       243       271       298      2,671     3,015     3,279
Mississippi         195       196       217      2,139     2,177     2,380
Other               11        6         326      118       67        3,581
Totals              1,748     1,427     1,775    19,209    15,857    19,511
Pro Forma           1,748     1,427     1,458    19,209    15,857    16,026
Totals^(1)

(1) Pro forma to exclude production from the Appalachian assets sold in July
2012.
Notes - Numbers may not add due to rounding.

Capital Expenditures

During the second quarter, capital expenditures were approximately $145
million, an increase of 53percent compared to $96million in the first
quarter, consisting of:

  *$116 million for drilling and completion activities;
  *$9 million for seismic, pipeline, gathering and facilities; and
  *$20 million for leasehold acquisitions, field projects and other.

The approximate $50 million increase in capital expenditures from the first
quarter to the second quarter was attributable to increased drilling,
completion and facility costs as a result of a larger drilling program
following the MHR Acquisition, as well as an approximate $15 million increase
in lease acquisition costs, primarily in the Eagle Ford Shale.

Operational Update

Eagle Ford Shale

Net production from the Eagle Ford Shale was 11,476 BOEPD in the second
quarter, compared to 7,523 BOEPD in the first quarter, or an increase of 53
percent.During the second quarter, we completed 17(10.8net) operated wells
and participated in the completion of two (0.9net) non-operated
wells.Currently, we have a total of 139(94.3net) Eagle Ford Shale producing
wells, with 15 (8.4 net) wells either completing or waiting on completion and
five (2.1 net) wells being drilled.We are currently running four operated
rigs, three of which are drilling and one of which is being retro-fitted to a
walking rig for use in pad drilling, and two non-operated rigs.

Set forth below are the results and statistics for recent Eagle Ford Shale
wells:

                                                       30-Day Average
                                  Peak Gross Daily Gross Daily          
                                      Production       Production
                                      Rates^(2)        Rates^(2)
                                                       
Well Name    Field /   Lateral Frac   Oil   Equivalent Oil    Equivalent
             Operator  Length Stages Rate  Rate       Rate   Rate
                     Feet          BOPD  BOEPD      BOPD   BOEPD
Operated                                                
wells
Othold #1H   Shiner    5,432   17     1,052 1,625      722    1,137
Elk Hunter   Peach     6,107   22     1,232 1,303      709    783
#1H          Creek
Elk Hunter   Peach     6,664   25     1,427 1,520      643    705
#2H          Creek
Elk Hunter   Peach     6,080   21     1,339 1,456      615    672
#3H          Creek
Hinze #1H    Shiner    5,323   22     742   1,113      538    849
Addax Hunter Peach     5,880   25     1,095 1,168      595    639
#1H          Creek
Addax Hunter Peach     5,727   24     1,157 1,246      681    737
#3H          Creek
Addax Hunter Peach     5,640   24     1,370 1,582      719    772
#2H          Creek
Dubose Unit  Cannonade 5,428   22     1,333 1,429      966    1,058
1 #2H
Dubose Unit  Cannonade 6,048   24     435   464        376    402
2 #1H
Garza-Kodack Cannonade 5,135   21     482   519        373    403
#1H
Netardus #1H Shiner    5,404   22     751   1,132      538    791
Douglas Raab Shiner    5,928   24     904   1,233      534    779
#1H
Buffalo      Peach     6,178   25     776   826        563    610
Hunter #1H   Creek
Gonzo South  Peach     6,428   18     707   752        443    481
#1H          Creek
Hefe Hunter  Shiner    5,590   23     1,641 1,894      1,090  1,295
#1H
Pilsner      Shiner    7,066   29     1,917 2,191      1,045  1,270
Hunter #1H
Schacherl    Shiner    4,295   18     1,131 1,272      678    788
#2H
Vana #3H     Shiner    5,138   21     1,039 1,212      ------ ------
Vana #4H     Shiner    4,852   20     888   1,038      ------ ------
Moose Hunter Shiner    4,326   18     1,379 1,528      ------ ------
#2H
Moose Hunter Shiner    5,836   24     1,506 1,694      ------ ------
#4H
                                                       
Averages (22
most recent           5,466   22     1,105 1,282      613    787
operated
wells)
Averages
(all 120              4,476   19     976   1,094      657    702
operated
wells)
                                                       
Non-operated                                            
wells
Cinco Ranch  Hunt             24     442   468        307    326
J #1H
Bubba        Hunt             29     465   478        119    171
Goodwin #1H
^(2)Wellhead rates only; the natural gas associated with these wells is
yielding between 165 and 315 barrels of NGLs per million cubic feet in         
Gonzales and Lavaca Counties.

Of our recent wells, 14 wells (Elk Hunter wells, Addax Hunter wells, Buffalo
Hunter and Gonzo South wells, Hefe Hunter and Pilsner Hunter wells, the Vana
wells and the Moose Hunter wells) were drilled off of six pads, with effective
spacing of between 45 and 70 acres.With continued leasing, primarily in
Gonzales and Lavaca Counties contiguous to our current acreage positions, and
continued success of our pad drilling efforts and shallower development
spacing, we anticipate that, over time, additional wells will be added to our
750-well drilling inventory.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of June 30, 2013, we had total debt of $1,142 million, consisting of $300
million principal amount of 7.25percent senior unsecured notes due 2019, $775
million of 8.50 percent senior unsecured notes due 2020 and $67 million
outstanding under our revolving credit facility (Revolver), with approximately
$280 million of unused borrowing capacity under the Revolver.Our indebtedness
at June 30, 2013, net of cash and cash equivalents, was $1,123million,
representing 56percent of book capitalization, with a leverage ratio under
the Revolver of 3.5 times trailing twelve months' pro forma Adjusted EBITDAX
of approximately $329million.

In May, the borrowing base and commitment under the Revolver was increased
from $276.2 million to $350.0 million.As a result, together with cash and
cash equivalents of $19 million, our financial liquidity was approximately
$300 million at June 30, 2013.The next borrowing base redetermination is
scheduled for November 2013.

During the second quarter, interest expense was $21.8million, compared to
$14.5million in the first quarter.We reported a $29.2 million loss on
extinguishment of debt ($10.0 million of which was non-cash) in connection
with the tender offer and redemption of our 10.375 percent senior notes due
2016.

During the second quarter, derivatives income was $8.6million, compared to a
derivatives loss of $7.8million in the first quarter.Second quarter 2013
cash settlements of derivatives resulted in net cash receipts of $2.2million,
compared to $3.6 million of net cash receipts in the first quarter.

Derivatives Update

To support our operating cash flows, we hedge a portion of our oil and natural
gas production at pre-determined prices or price ranges.Based on hedges
currently in place, we have hedged approximately 9,500barrels of daily crude
oil production in the second half of 2013, or approximately 76 percent of the
midpoint of guidance for second half 2013 crude oil production, at a weighted
average floor/swap price of $94.69 per barrel.We have also hedged
approximately 25,000 MMBtu of daily natural gas production in the second half
of 2013, or approximately 67 percent of the midpoint of guidance for second
half 2013 natural gas production, at a weighted average floor/swap price of
$3.79 per Mcf.

Please see the Derivatives Table included in this release for our current
derivative positions.

2013 Guidance

Previous guidance refers to guidance provided in the first quarter 2013
earnings release, which excluded the impact of the exercise of preferential
rights by our Eagle Ford Shale partners as announced in June 2013.Updated
2013 guidance highlights are as follows:

  *Production is expected to be 6.8 to 7.5 MMBOE, or approximately 18,500 to
    20,600 BOEPD, compared to previous guidance of 6.7 to 7.3 MMBOE, or
    approximately 18,200 to 20,000 BOEPD.

    *Crude oil production is expected to increase by 55 to 78 percent over
      2012 levels, compared to previous guidance of 60 to 78 percent
      growth.Crude oil and NGLs are expected to comprise 63 to 69percent of
      total production, compared to previous guidance of 65 to 69 percent
      growth.

  *Product revenues, excluding the impact of any hedges, are expected to be
    $416 to $471 million, slightly higher than previous guidance of $414 to
    $469 million.

    *Crude oil and NGL product revenues are expected to be 86 to 89 percent
      of total product revenues, unchanged from previous guidance.

    *Settlements of current commodity hedges are expected to result in cash
      receipts of approximately $12million in 2013.

  *Adjusted EBITDAX, a non-GAAP measure, is expected to be $310 to $350
    million, compared to previous guidance of $300 to $360 million.
    
  *Capital expenditures are expected to be $470 to $510million, compared to
    previous guidance of $445 to $505million.The increase is due primarily
    to $13 to $19 million of additional lease acquisition opportunities,
    primarily in the Eagle Ford Shale.

    *Approximately 92 percent of capital expenditures are expected to be
      allocated to the Eagle Ford Shale.

    *2013 capital expenditures include $413 to $437 million for drilling and
      completions (compared to previous guidance of $400 to $450 million), $36
      to $49 million for lease acquisitions (compared to previous guidance of
      $23 to $30 million) and $21 to $24 million for pipeline, gathering,
      seismic and facilities (compared to previous guidance of $22 to $25
      million).

    *We expect to drill 69 (42.3 net) Eagle Ford Shale wells during 2013,
      excluding 16 (7.0 net) wells drilled by MHR and another operator prior
      to the closing of the MHR Acquisition.

Please see the Guidance Table included in this release for guidance estimates
for 2013.These estimates are meant to provide guidance only and are subject
to revision as our operating environment changes.


Explanation of Non-GAAP Operating Margin per BOE

Operating margin is a non-GAAP financial measure under SEC regulations which
represents total product revenues less total direct operating expenses,
excluding acquisition transaction expenses.Operating margin per BOE is equal
to operating margin divided by total equivalent crude oil, NGL and natural gas
production.Operating margin is not adjusted for the impact of hedges.We
believe that operating margin per BOE is an important measure that can be used
by security analysts and investors to evaluate our operating margin per unit
of production and to compare it to other oil and gas companies, as well as for
comparisons to other time periods.

Second Quarter 2013 Conference Call

A conference call and webcast, during which management will discuss second
quarter 2013 financial and operational results, is scheduled for Thursday,
August 8, 2013 at 10:00 a.m. ET.Prepared remarks by H. Baird Whitehead,
President and Chief Executive Officer, will be followed by a question and
answer period.Investors and analysts may participate via phone by dialing
toll free 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes
before the scheduled start of the conference call (use the conference code
33058530), or via webcast by logging on to our website, www.pennvirginia.com,
at least 15 minutes prior to the scheduled start of the call to download and
install any necessary audio software.A telephonic replay will be available
for two weeks beginning approximately 24 hours after the call.The replay can
be accessed by dialing toll free 1-855-859-2056 (international:
1-404-537-3406) and using the replay code 33058530.In addition, an on-demand
replay of the webcast will also be available for two weeks at our website
beginning approximately 24 hours after the webcast.

Penn Virginia Corporation (NYSE:PVA) is an independent oil and gas company
engaged primarily in the exploration, development and production of oil, NGLs
and natural gas in various domestic onshore regions of the United States, with
a primary focus in Texas, and to a lesser extent, the Mid-Continent,
Mississippi and the Marcellus Shale in Appalachia.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 oil, NGLs and natural gas;
our ability to develop, explore for, acquire and replace oil and natural gas
reserves and sustain production; our ability to generate profits or achieve
targeted reserves in our development and exploratory drilling and well
operations; any impairments, write-downs or write-offs of our reserves or
assets; the projected demand for and supply of oil, NGLs and natural gas;
reductions in the borrowing base under our revolving credit facility; our
ability to contract for drilling rigs, supplies and services at reasonable
costs; our ability to obtain adequate pipeline transportation capacity for our
oil and gas production at reasonable cost and to sell the production at, or at
reasonable discounts to, market prices; the uncertainties inherent in
projecting future rates of production for our wells and the extent to which
actual production differs from estimated proved oil and natural gas reserves;
drilling and operating risks; our ability to compete effectively against other
independent and major oil and natural gas companies; our ability to
successfully monetize select assets and repay our debt; leasehold terms
expiring before production can be established; environmental liabilities that
are not covered by an effective indemnity or insurance; the timing of receipt
of necessary regulatory permits; the effect of commodity and financial
derivative arrangements; our ability to maintain adequate financial liquidity
and to access adequate levels of capital on reasonable terms; the occurrence
of unusual weather or operating conditions, including force majeure events;
our ability to retain or attract senior management and key technical
employees; counterparty risk related to their ability to meet their future
obligations; changes in governmental regulations or enforcement practices,
especially with respect to environmental, health and safety matters;
uncertainties relating to general domestic and international economic and
political conditions; and other risks set forth in our filings with the
Securities and Exchange Commission (SEC).

Additional information concerning these and other factors can be found in our
press releases and public periodic filings with the SEC.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 a result of new
information, future events or otherwise.

                                                              
PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - unaudited
(in thousands, except per share data)
                                                              
                        Three months ended         Six months ended
                         June 30,                   June 30,
                        2013          2012         2013          2012
Revenues                                                       
Crude oil                $86,867     $58,382    $149,925    $117,105
Natural gas liquids      7,313        7,556       14,440       16,627
(NGLs)
Natural gas              15,554       10,303      27,593       25,189
Total product revenues  109,734      76,241      191,958      158,921
Gain (loss) on sales of
property and equipment,  256          78          (293)        834
net
Other                    (335)        526         1,188        1,501
Total revenues          109,655      76,845      192,853      161,256
Operating expenses                                             
Lease operating          8,629        9,264       16,434       18,407
Gathering, processing    2,980        4,391       6,559        8,545
and transportation
Production and ad        6,976        (254)       12,935       3,326
valorem taxes
General and
administrative
(excluding               12,970       10,411      22,828       20,937
equity-classified
share-based
compensation) (a)
Total direct operating  31,555       23,812      58,756       51,215
expenses
Share-based compensation
- equity classified      2,686        1,336       3,771        2,951
awards (b)
Exploration             7,845        9,384       14,140       17,382
Depreciation, depletion  64,329       51,740      115,905      102,557
and amortization
Impairments              --           28,616      --           28,616
Total operating         106,415      114,888     192,572      202,721
expenses
                                                              
Operating income (loss)  3,240        (38,043)    281          (41,465)
                                                              
Other income (expense)                                         
Interest expense        (21,808)     (15,084)    (36,287)     (29,858)
Loss on extinguishment   (29,157)     --          (29,157)     --
of debt
Derivatives              8,588        43,826      827          43,521
Other                    17           28          44           29
                                                              
Loss before income       (39,120)     (9,273)     (64,292)     (27,773)
taxes
Income tax benefit       13,682       3,635       22,471       10,236
Net loss                 (25,438)     (5,638)     (41,821)     (17,537)
Preferred stock          (1,725)      --          (3,450)      --
dividends
                                                              
Loss applicable to       $(27,163)   $(5,638)   $(45,271)   $(17,537)
common shareholders
                                                              
Loss per share:                                                
Basic                    $(0.43)     $(0.12)    $(0.77)     $(0.38)
Diluted                  $(0.43)     $(0.12)    $(0.77)     $(0.38)
                                                              
Weighted average shares  62,899       46,030      59,141       45,988
outstanding, basic
Weighted average shares  62,899       46,030      59,141       45,988
outstanding, diluted
                                                              
                                                              
                        Three months ended         Six months ended
                         June 30,                   June 30,
                        2013          2012         2013          2012
Production                                                     
Crude oil (MBbls)        858          572         1,457        1,120
NGLs (MBbls)             260          227         494          442
Natural gas (MMcf)       3,778        5,859       7,342        12,153
Total crude oil, NGL and
natural gas production   1,748        1,775       3,175        3,588
(MBOE)
                                                              
Prices                                                         
Crude oil ($ per Bbl)    $101.23     $102.14    $102.89     $104.55
NGLs ($ per Bbl)         $28.10      $33.23     $29.21      $37.60
Natural gas ($ per Mcf)  $4.12       $1.76      $3.76       $2.07
                                                              
Prices - Adjusted for                                          
derivative settlements
Crude oil ($ per Bbl)    $104.10     $102.03    $106.52     $104.40
NGLs ($ per Bbl)         $28.10      $33.23     $29.21      $37.60
Natural gas ($ per Mcf)  $4.06       $2.72      $3.83       $3.20
                                                              
(a) Includes liability-classified share-based compensation expense
attributable to our performance-based restricted stock units which are payable
in cash upon the achievement of certain market-based performance metrics. A
total of $0.4 million and $0.6 million attributable to these awards is
included in the three and six months ended June 30, 2013 and 2012.

(b) Our equity-classified share-based compensation expense includes non-cash
charges for our stock option expense and the amortization of common, deferred
and restricted stock and restricted stock unit awards related to
equity-classified employee and director compensation in accordance with
accounting guidance for share-based payments.

PENN VIRGINIA CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
                                                 As of                   
                                                 June 30,    December 31,
                                                    2013        2012
Assets                                                       
Current assets                                    $169,829   $96,515
Net property and equipment                        2,234,256  1,723,359
Other assets                                      40,918     23,115
Total assets                                      $2,445,003 $1,842,989
                                                            
Liabilities and shareholders'                                
equity
Current liabilities                               $188,380   $112,025
Revolving credit facility                         67,000     --
Senior notes due 2016                             --         294,759
Senior notes due 2019                             300,000    300,000
Senior notes due 2020                             775,000    --
Other liabilities and deferred                    219,236    241,089
income taxes
Total shareholders' equity                        895,387    895,116
Total liabilities and                             $2,445,003 $1,842,989
shareholders' equity
                                                            
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
                                                            
                                                  
                              Three months ended   Six months ended
                               June 30,             June 30,
                              2013       2012      2013        2012
Cash flows from operating                                    
activities
Net loss                      $(25,438)  $(5,638)  $(41,821)   $(17,537)
Adjustments to reconcile net
loss to net cash provided by                                 
operating activities:
Loss on extinguishment of     29,157    --       29,157     --
debt
Depreciation, depletion and   64,329    51,740   115,905    102,557
amortization
Impairments                   --        28,616   --         28,616
Derivative contracts:                                       
Net gains                     (8,588)   (43,826) (827)      (43,521)
Cash settlements              2,233     6,970    5,790      14,951
Deferred income tax benefit   (13,682)  (3,635)  (22,471)   (10,236)
Loss (gain) on sales of       (256)     (78)     293        (834)
assets, net
Non-cash exploration expense  5,146     8,284    10,408     16,455
Non-cash interest expense     939       1,035    1,885      2,050
Share-based compensation      2,686     1,336    3,771      2,951
(equity-classified)
Other, net                    650       147      938        203
Changes in operating assets   26,960    73       26,723     20,070
and liabilities
Net cash provided by          84,136    45,024   129,751    115,725
operating activities
Cash flows from investing                                    
activities
Acquisition, net              (358,239) --       (358,239)  --
Payments to settle
obligations assumed in         (36,310)  --       (36,310)   --
acquisition, net
Capital expenditures -        (143,346) (93,767) (229,319)  (188,236)
property and equipment
Proceeds from sales of        (11)      (251)    867        527
assets, net
Other, net                    --        180      --         180
Net cash used in investing    (537,906) (93,838) (623,001)  (187,529)
activities
Cash flows from financing                                    
activities
Proceeds from the issuance of 775,000   --       775,000    --
senior notes
Retirement of senior notes    (319,090) --       (319,090)  --
Proceeds from revolving       115,000   61,000   153,000    84,000
credit facility borrowings
Repayment of revolving credit (86,000)  --       (86,000)   (3,000)
facility borrowings
Debt issuance costs paid      (24,698)  --       (24,698)   --
Dividends paid on preferred   (1,725)   (2,590)  (3,412)    (5,176)
and common stock
Other, net                    (49)      --       (110)      --
Net cashprovided by          458,438   58,410   494,690    75,824
financing activities
Net increase (decrease) in     4,668     9,596    1,440      4,020
cash and cash equivalents
Cash and cash equivalents -    14,422    1,936    17,650     7,512
beginning of period
Cash and cash equivalents -    $19,090    $11,532   $19,090     $11,532
end of period
                                                            
Supplemental disclosures of                                  
cash paid for:
Interest (net of amounts      $22,875    $26,099   $23,215     $26,656
capitalized)
Income taxes (net of refunds  $--        $(10)     $--         $(311)
received)

                                                              
PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
                                                              
                                                              
                        Three months ended          Six months ended
                         June 30,                    June 30,
                        2013          2012          2013         2012
Reconciliation of GAAP
"Net loss" to Non-GAAP
"Net loss applicable to                                        
common shareholders, as
adjusted"
Net loss                 $(25,438)   $(5,638)    $(41,821)  $(17,537)
Adjustments for                                                
derivatives:
Net losses              (8,588)      (43,826)     (827)       (43,521)
Cash settlements        2,233        6,970        5,790       14,951
Adjustment for
acquisition transaction  2,396        --          2,396       --
expenses
Adjustment for           --          28,616       --         28,616
impairments
Adjustment for           --          (148)        --         (148)
restructuring costs
Adjustment for loss
(gain) on sale of        (256)        (78)         293         (834)
assets, net
Adjustment for loss on   29,157       --          29,157      --
extinguishment of debt
Impact of adjustments on (8,723)      3,319        (12,865)    345
income taxes
Preferred stock          (1,725)      --          (3,450)     --
dividends
Net loss applicable to
common shareholders, as  $(10,944)   $(10,785)   $(21,327)  $(18,128)
adjusted (a)
                                                              
Net loss applicable to
common shareholders, as  $(0.17)     $(0.23)     $(0.36)    $(0.39)
adjusted, per share,
diluted
                                                              
Reconciliation of GAAP
"Net loss" to Non-GAAP                                         
"Adjusted EBITDAX"
Net loss                 $(25,438)   $(5,638)    $(41,821)  $(17,537)
Income tax benefit       (13,682)     (3,635)      (22,471)    (10,236)
Interest expense         21,808       15,084       36,287      29,858
Depreciation, depletion  64,329       51,740       115,905     102,557
and amortization
Exploration              7,845        9,384        14,140      17,382
Share-based compensation
expense                  2,686        1,336        3,771       2,951
(equity-classified
awards)
EBITDAX                  57,548       68,271       105,811     124,975
Adjustments for                                                
derivatives:
Net losses              (8,588)      (43,826)     (827)       (43,521)
Cash settlements        2,233        6,970        5,790       14,951
Adjustment for
acquisition transaction  2,396        --          2,396       --
expenses
Adjustment for           --          28,616       --         28,616
impairments
Adjustment for loss
(gain) on sale of        (256)        (78)         293         (834)
assets, net
Adjustment for other     647          --          854         --
non-cash items
Adjustment for loss on   29,157       --          29,157      --
extinguishment of debt
Adjusted EBITDAX (b)     $83,137     $59,953     $143,474   $124,187
                                                              
(a) Net loss applicable to common shareholders, as adjusted, represents the
net loss adjusted to exclude the effects of non-cash changes in the fair value
of derivatives, acquisition transaction expenses, impairments, restructuring
costs, net gains and losses on the sale of assets, loss on extinguishment of
debt and preferred stock dividends.We believe this presentation is commonly
used by investors and professional research analysts in the valuation,
comparison, rating and investment recommendations of companies within the oil
and gas exploration and production industry. We use this information for
comparative purposes within our industry. Net loss applicable to common, as
adjusted, is not a measure of financial performance under GAAP and should not
be considered as a measure of liquidity or as an alternative to net loss.

(b) Adjusted EBITDAX represents net loss before income tax expense or benefit,
interest expense, depreciation, depletion and amortization expense,
exploration expense and share-based compensation expense, further adjusted to
exclude the effects of non-cash changes in the fair value of derivatives,
acquisition transaction expenses, impairments, net gains and losses on the
sale of assets, loss on extinguishment of debt and other non-cash items. We
believe this presentation is commonly used by investors and professional
research analysts in the valuation, comparison, rating and investment
recommendations of companies within the oil and gas exploration and production
industry. We use this information for comparative purposes within our
industry. Adjusted EBITDAX is not a measure of financial performance under
GAAP and should not be considered as a measure of liquidity or as an
alternative to net loss. Adjusted EBITDAX represents EBITDAX as defined in our
revolving credit facility.

                                                                 
PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited
(dollars in millions except where noted)
                                                                 
We are providing the following guidance regarding financial and operational
expectations for full-year 2013. These estimates are meant to provide guidance
only and are subject to change as PVA's operating environment changes.
                                                                 
                                                                 
                     First     Second
                    Quarter   Quarter   Year-to-Date   Full-Year
                     2013      2013      2013           2013 Guidance
Production:                                                       
Crude oil (MBbls)    599       858       1,457          3,500    --  4,000
NGLs (MBbls)        234       260       494            925      --  1,025
Natural gas (MMcf)  3,565     3,778     7,342          14,000   --  15,000
Equivalent           1,427     1,748     3,175          6,758    --  7,525
production (MBOE)
Equivalent daily     15,857    19,209    17,542         18,516   --  20,616
production (BOEPD)
Percent crude oil    58.4%     64.0%     61.5%          63.0%    --  69.0%
and NGLs
                                                                 
Production revenues                                               
(a):
Crude oil           $63.1     86.9      149.9          340.0    --  385.0
NGLs                $7.1      7.3       14.4           26.0     --  29.0
Natural gas          $12.0     15.6      27.6           50.0     --  57.0
Total product        $82.2     109.7     192.0          416.0    --  471.0
revenues
Total product        $57.61    62.78     60.46          61.55    --  62.59
revenues ($ per BOE)
Percent crude oil    85.4%     85.8%     85.6%          86.3%    --  89.4%
and NGLs
                                                                 
Operating expenses:                                               
Lease operating ($  $5.47     4.94      5.18           5.60     --  6.00
per BOE)
Gathering,
processing and       $2.51     1.70      2.07           1.70     --  1.85
transportation costs
($ per BOE)
Production and ad
valorem taxes        7.2%      6.4%      6.7%           6.6%     --  7.0%
(percent of oil and
gas revenues)
                                                                 
General and                                                       
administrative:
Recurring general   $9.9      10.6      20.4           41.0     --  43.0
and administrative
Share-based         $1.1      2.7       3.8            5.0      --  6.5
compensation
Acquisition         $------   2.4       2.4            2.4      --  2.4
transaction expenses
Total reported G&A   $10.9     15.7      26.6           48.4     --  51.9
                                                                 
Exploration:                                                      
Total reported      $6.3      7.8       14.1           40.0     --  43.0
exploration
Unproved property   $5.3      5.1       10.4           36.5     --  39.0
amortization
                                                                 
Depreciation,
depletion and        $36.14    36.80     36.50          36.00    --  39.00
amortization ($ per
BOE)
                                                                 
Adjusted EBITDAX (b) $60.3     83.1      143.5          310.0    --  350.0
                                                                 
Capital                                                           
expenditures:
Drilling and         $86.5     116.3     202.9          413.0    --  437.0
completion
Pipeline, gathering, $3.0      8.2       11.2           18.0     --  20.0
facilities
Seismic (c)          $1.0      1.8       2.8            3.0      --  4.0
Lease acquisitions,
field projects and   $5.1      19.9      25.0           36.0     --  49.0
other
Total capital       $95.6     146.2     241.8          470.0    --  510.0
expenditures
                                                                 
End of period debt   $633.1    1,142.0   1,142.0        1,210.0  --  1,250.0
outstanding
Interest expense:                                                 
Total reported      $14.5     21.8      36.3           78.0     --  84.0
interest expense
Cash interest       $13.5     20.9      34.4           76.0     --  77.0
expense
Preferred stock      $1.7      1.7       3.4            6.9      --  6.9
dividends paid
Income tax benefit   34.9%     35.0%     35.0%          35.5%    --  36.5%
rate
                                                                 
(a) Assumes average benchmark prices of $92.87 per barrel for crude oil and
$3.69 per MMBtu for natural gas, prior to any premium or discount for quality,
basin differentials, the impact of hedges and other adjustments.NGL realized
pricing is assumed to be $28.49 per barrel.

(b) Adjusted EBITDAX is not a measure of financial performance under GAAP and
should not be considered as a measure of liquidity or as an alternative to net
income.

(c) Seismic expenditures are also reported as a component of exploration
expense and as a component of net cash provided by operating activities.

                                                        
PENN VIRGINIA CORPORATION                                                 
GUIDANCE TABLE - unaudited - (continued)                                  
                                                        
                                                        
Note to Guidance Table:                                                   
                                                        
The following table shows our current                      
derivative positions.
                                                        
                                             Weighted Average Price
               Instrument Type  Average Volume Floor/      Ceiling
                                 Per Day        Swap
                                                        
Natural gas:                    (MMBtu)        ($ / MMBtu)
Third quarter   Collars         10,000         3.50        4.30
2013
Fourth quarter  Collars         15,000         3.67        4.37
2013
First quarter   Collars         5,000          4.00        4.50
2014
Third quarter   Swaps            15,000         3.92        
2013
Fourth quarter  Swaps            10,000         4.04        
2013
First quarter   Swaps            10,000         4.28        
2014
Second quarter  Swaps            15,000         4.10        
2014
Third quarter   Swaps            15,000         4.10        
2014
Fourth quarter  Swaps            5,000          4.50        
2014
First quarter   Swaps            5,000          4.50        
2015
                                                        
Crude oil:                      (barrels)      ($ / barrel)
Bitmap Bitmap
Bitmap Bitmap   Collars         2,232          90.74       99.78
Third quarter
2013
Fourth quarter  Collars         2,400          91.04       100.02
2013
First quarter   Collars         500            90.00       97.60
2014
Second quarter  Collars         500            90.00       97.60
2014
Third quarter   Swaps            6,832          95.84       
2013
Fourth quarter  Swaps            7,500          95.98       
2013
First quarter   Swaps            7,500          93.86       
2014
Second quarter  Swaps            7,500          93.86       
2014
Third quarter   Swaps            7,000          93.23       
2014
Fourth quarter  Swaps            6,500          92.98       
2014
First quarter   Swaption (a)     812            100.00      
2014
Second quarter  Swaption (a)     812            100.00      
2014
Third quarter   Swaption (a)     812            100.00      
2014
Fourth quarter  Swaption (a)     812            100.00      
2014
                                                        
(a)This written swaption contract gives our counterparties the option
to enter into a fixed price swap with us at a future date.If the
forward commodity price for calendar year 2014 is higher than or equal
to $100.00 per barrel on December 31, 2013, the counterparty will
exercise its option to enter into a fixed price swap at $100.00 per
barrel for calendar year 2014, at which point the contract functions
as a fixed price swap.If the forward commodity price for calendar
year 2014 is lower than $100.00 per barrel on December 31, 2013, the
option expires and no fixed price swap is in effect.

We estimate that, excluding the derivative positions described above,
for every $1.00 per MMBtu increase or decrease in the natural gas
price, operating income for 2013 would increase or decrease by
approximately $6.7 million.In addition, we estimate that for every
$10.00 per barrel increase or decrease in the crude oil price,
operating income for 2013 would increase or decrease by approximately
$31.1 million.This assumes that crude oil prices, natural gas prices
and inlet volumes remain constant at anticipated levels.These
estimated changes in operating income exclude potential cash receipts
or payments in settling these derivative positions.

CONTACT: James W. Dean
         Vice President, Corporate Development
         Ph: (610) 687-7531 Fax: (610) 687-3688
         E-Mail: invest@pennvirginia.com

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