Penn Virginia Corporation Announces Third Quarter 2010 Results

Penn Virginia Corporation (NYSE: PVA) today reported financial and
operational results for the three months ended September 30, 2010,
provided an update of full-year 2010 guidance and issued preliminary
full-year 2011 guidance.

Third Quarter 2010 Highlights

Third quarter 2010 results, with comparisons to third quarter 2009
results, included the following:

• 
  Quarterly oil and gas production of 13.3 billion cubic feet of natural
  gas equivalent (Bcfe), or 144.3  million cubic feet of natural gas
  equivalent (MMcfe) per day, a 19 percent increase as compared to 11.2
  Bcfe, or 121.3 MMcfe per day, pro forma to exclude production from
  Gulf Coast assets sold in January 2010 (27 percent sequential increase
  as compared to 10.5 Bcfe, or 115.1 MMcfe per day, in the second
  quarter of 2010);
  
• 
  Operating loss of $53.1  million, as compared to a loss of $122.1
  million, with significant impairment charges in both periods;
  
• 
  Net loss from continuing operations of $30.2 million, or $0.66 per
  diluted share, as compared to a loss of $84.7  million, or $1.87 per
  diluted share; and
  
• 
  Adjusted net loss attributable to PVA, a non-GAAP measure which
  excludes the effects of impairments, non-cash change in derivatives
  fair value, drilling rig standby charges, restructuring costs, and
  other gains or losses that affect comparability to the prior year
  period, of $13.9 million, or $0.31 per diluted share, as compared to a
  loss of $10.9 million, or $0.24 per diluted share.
  

The operating loss and net loss from continuing operations in the third
quarter of 2010, as reported above, included impairment charges of $35.1
million and dry hole costs of $9.0 million in the Mid-Continent region,
as discussed in further detail below.

Reconciliations of non-GAAP financial measures to GAAP-based measures
appear in the financial tables later in this release.

Management Comment

A. James Dearlove, President and Chief Executive Officer said,
'Production increased significantly during the third quarter of 2010 as
compared to the previous quarter and the prior year quarter due to a
resumption of drilling activity in late 2009 and a 'catch-up' of
completion activity following delays earlier in 2010. Production
increases from the Granite Wash and Haynesville Shale were the primary
drivers of production growth in the third quarter.

'Due to the recent decline in natural gas prices, in both the spot and
futures markets, and with little in the way of catalysts to improve the
situation in the near-term, we have elected to further increase our
exposure to oil and liquids plays by shifting drilling from East Texas
to our recently acquired Eagle Ford Shale acreage. In addition, we will
shift drilling from Mississippi to the Marcellus Shale as we commence
testing of our acreage in Pennsylvania. We believe that testing both our
Eagle Ford Shale and Marcellus Shale positions are more value-added uses
of capital in the near term than drilling in East Texas and Mississippi,
despite encouraging recent results, as acreage in these two areas is
largely held-by-production.

'As a result of this shift in drilling activity, we expect declines in
production from East Texas and Mississippi until there is a meaningful
recovery in natural gas prices. These production declines are expected
to be offset in 2011 by production growth from the Granite Wash and
other liquids-rich Mid-Continent plays, as well as expected production
contributions from the Eagle Ford and Marcellus Shales.

'In this release, we have provided a preliminary view into 2011 where,
relative to 2010, we expect to spend approximately 40 percent less on
capital expenditures, while still growing production by a midpoint of
approximately 11  percent. This reduction in capital spending, along with
expected financial liquidity of over $500 million as we enter 2011, plus
operating cash flows expected during 2011, will keep Penn Virginia on
very solid financial footing and allow us to react to changing market
conditions.?

Third Quarter 2010 Financial and Operational Results

Production in the third quarter of 2010 was approximately 13.3 Bcfe, or
144.3 MMcfe per day, 19  percent more than the pro forma 11.2 Bcfe, or
121.3 MMcfe per day, in the third quarter of 2009 and 27 percent more
than the 10.5 Bcfe, or 115.1 MMcfe per day, in the second quarter of
2010. The year-over-year increase was due to the effects of
significantly increased drilling activity during 2010 and, to a lesser
extent, by increased production of natural gas liquids (NGLs) and crude
oil primarily from the Granite Wash play. See our separate operational
update news release dated November 3, 2010 for a more detailed
discussion of operations.

Our realized natural gas price, prior to the impact of derivatives,
during the third quarter of 2010 was $4.36 per thousand cubic feet
(Mcf), 26 percent higher than the $3.45 per Mcf price in the third
quarter of 2009 and three percent higher than the $4.25 per Mcf price in
the second quarter of 2010. Our realized oil price, prior to the impact
of derivatives, during the third quarter of 2010 was $70.97 per barrel,
eight percent higher than the $65.64 per barrel price in the third
quarter of 2009, but four percent lower than the $73.58  per barrel price
in the second quarter of 2010. Our realized NGLs price during the third
quarter of 2010 was $35.57 per barrel, 17  percent higher than the $30.29
per barrel price in the third quarter of 2009 and two percent higher
than the $35.03 per barrel price in the second quarter of 2010.
Adjusting for oil and gas hedges, our effective natural gas price during
the third quarter of 2010 was $5.05 per Mcf and our effective oil price
was $70.62 per barrel, or an increase of $0.69 per Mcf and decrease of
$0.35 per barrel, respectively, over the realized prices.

The operating loss of $53.1 million was a $69.0 million improvement over
the operating loss of $122.1  million in the prior year quarter, due
primarily to an approximate $57.2 million decrease in impairment
charges. The remaining $11.8  million decrease in operating loss was
primarily due to the production increase and a 21 percent increase in
the realized gas equivalent commodity price, from $4.25 to $5.15 per
Mcfe.

As discussed below, third quarter 2010 direct operating expenses
increased $3.4 million, or 13 percent, to $29.9  million as compared to
$26.5 million in the third quarter of 2009.

• 
  Lease operating expenses decreased by $1.5 million, or 14 percent, to
  $9.3 million, or $0.70  per Mcfe produced, from $10.8 million, or $0.87
  per Mcfe produced, resulting primarily from lower charges for
  equipment and compressor rentals, water disposal and contract labor,
  partially offset by higher repairs and maintenance costs;
  
• 
  Gathering, processing and transportation expenses increased by $1.2
  million, or 50 percent, to $3.6  million, or $0.27 per Mcfe produced,
  from $2.4 million, or $0.20 per Mcfe produced, resulting primarily
  from the production increase and a change in the geographic
  distribution of production from divested Gulf Coast assets to the
  Mid-Continent region;
  
• 
  Production and ad valorem taxes increased by $1.5 million, or 38
  percent, to $5.3  million, or 7.8  percent of total oil and gas
  revenues, from $3.8  million, or 7.3  percent of total oil and gas
  revenues, due to the production increase and a shift in production mix
  towards higher tax areas in the current year period; and
  

• 
  General and administrative expense increased by $2.3 million to $11.7
  million from $9.5  million, resulting from restructuring charges of
  $0.8 million as well as higher consulting and professional fees in the
  third quarter of 2010.
  

Exploration expense increased $5.9 million, or 37  percent, to
$22.0  million in the third quarter of 2010 from $16.1  million in the
prior year quarter, primarily due to a $9.0 million charge for a dry
hole in the Granite Wash and a $4.0 million increase in seismic costs,
partially offset by a decrease in drilling rig standby charges relative
to the prior year quarter.

Depreciation, depletion and amortization expenses decreased by $7.1
million, or 18 percent, to $33.2  million, or $2.50 per Mcfe, in the
third quarter of 2010 from $40.3 million, or $3.25 per Mcfe, in the
prior year quarter due to lower depletion rates in various plays due to
mid-year reserve additions and impairments.

Impairments decreased by approximately $57.2 million, or 62 percent, to
$35.1  million in the third quarter of 2010 from $92.4  million in the
prior year quarter. In the prior year quarter, we recorded an $87.9
million impairment charge related to Gulf Coast assets held for sale. We
recorded a $32.6 million impairment charge in the third quarter of 2010
primarily related to coal bed methane properties in the Mid-Continent
region due to market declines in spot and future natural gas prices.

Full-Year 2010 Guidance Update

Full-year 2010 guidance highlights are as follows:

• 
  Full-year 2010 production guidance of 46.5 to 47.5 Bcfe, which
  reflects a reduction from the previous guidance range of 47.0 to 50.0
  Bcfe as a result of an expected reduction in non-operated drilling and
  completion activity in the Granite Wash play, as well as East Texas
  and Mississippi, during the fourth quarter of 2010;
  
• 
  Decreased fourth quarter production guidance to a range of 12.4 to
  13.4  Bcfe, from a previous guidance range of 14.0 to 15.7 Bcfe, as
  discussed above; and
  
• 
  Decreased oil and gas capital expenditures guidance to a range of $465
  to $485 million from a range of $480 to $520 million of previous
  guidance (adjusted to reflect a $31.1 million Eagle Ford Shale
  acquisition announced in August 2010) due to reduced drilling and
  completion activity in the Granite Wash (non-operated), East Texas and
  Mississippi.
  

Our currently anticipated oil and gas capital expenditures for 2010
include $300 to $310 million for drilling and completion activity and
$145 to $150 million for land acquisitions. The reduced level of
non-operated Granite Wash drilling during the fourth quarter of 2010
relates to a scheduled rotation of rigs operated by our joint venture
partner to other locations outside of our area of mutual interest (AMI).
The non-operated rig count, which has decreased to one rig currently, is
expected to increase in the first quarter of 2011.

See the Guidance Table included in this release for guidance estimates
for full-year 2010. These estimates, including capital expenditure
plans, are meant to provide guidance only and are subject to revision as
our operating environment changes.

Preliminary Full-Year 2011 Guidance

As a result of the sale of non-core assets and other financing
transactions during the past two years, we expect to have over $500
million of available liquidity in the form of cash and equivalents and
revolver availability as we enter 2011. Assuming 2011 oil and gas
capital expenditures are between $250 and $300  million, or approximately
35 to 45 percent lower than the midpoint of revised 2010 capital
expenditures guidance, full-year 2011 production is estimated to be
approximately 50 to 54 Bcfe. This range of preliminary 2011 production
guidance is approximately six to 15 percent higher than the midpoint of
revised 2010 production guidance. Our existing financial liquidity and
expected cash flows from operating activities are expected to be
sufficient to fund our anticipated 2011 activity levels.

Capital Resources and Liquidity, Interest Expense and Impact of
Derivatives

As of September 30, 2010, we had outstanding borrowings of $530.0
million ($504.5 million carrying value), consisting of $300 million
($292 million carrying value) of senior unsecured notes due 2016 and
$230  million ($212  million carrying value) of convertible senior
subordinated notes due 2012, with no borrowings under our revolving
credit facility. Net of cash and equivalents of $205 million, our net
indebtedness at September 30, 2010 was $300 million.

Currently, we have approximately $625 million of financial liquidity,
excluding cash flows from operating activities, comprised of cash on
hand ($205 million), committed availability under our revolving credit
facility ($300 million) and an additional $120 million of borrowing base
availability. Together with ongoing cash flows from operating
activities, supplemented by natural gas and crude oil hedges, we expect
this financial liquidity to be sufficient to fund our anticipated
capital needs for the remainder of 2010 and 2011.

Interest expense decreased to $13.2  million in the third quarter of 2010
from $16.3  million in the third quarter of 2009. The decrease was
primarily due to a $2.9 million reclassification to expense from
accumulated other comprehensive income in the third quarter of 2009 as a
result of the discontinuation of hedge accounting related to our
interest rate swaps. Cash interest expense decreased from $11.1 million
in the prior year quarter to $10.8 million in the third quarter of 2010,
because we had no outstanding borrowings under our revolving credit
facility during 2010.

Due to fluctuations in commodity prices during the third quarter of
2010, derivatives income was $15.1  million as compared to derivatives
income of $0.3 million in the prior year quarter. Third quarter 2010
cash settlements of our derivatives resulted in net cash receipts of
$6.8  million, as compared to $15.8 million of net cash receipts in the
prior year quarter.

Third Quarter 2010 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
third quarter 2010 financial and operational results, is scheduled for
Thursday, November 4, 2010 at 10:00 a.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 1-866-630-9986 five to ten minutes
before the scheduled start of the conference call (use the passcode
9601694), 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 888-203-1112
(international: 719-457-0820) and using the replay code 9601694. 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 natural gas
and oil company focused on the exploration, acquisition, development and
production of reserves in onshore regions of the U.S., including
Oklahoma, Texas, the Appalachian Basin and Mississippi.

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, natural gas liquids, or NGLs, and
crude oil; our ability to access external sources of capital;
uncertainties relating to the occurrence and success of capital-raising
transactions, including securities offerings and asset sales; reductions
in the borrowing base under the Revolver; our ability to develop and
replace oil and gas reserves and the price for which such reserves can
be acquired; any impairment write-downs of our reserves or assets;
reductions in our anticipated capital expenditures; the relationship
between natural gas, NGL and crude oil; 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
industry generally; the extent to which the amount and quality of actual
production of our oil and natural gas differ from estimated proved oil
and gas reserves; operating risks, including unanticipated geological
problems, incidental to our business; 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; 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; 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); and other risks set forth in our
Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

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,
2009. 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.

(a) Includes restructuring costs of $0.8 million and $6.4 million for
the three and nine months ended September 30, 2010, respectively.

(b)
Our equity-based compensation expense includes our stock option expense
and the amortization of restricted stock and restricted stock units
related to employee awards in accordance with accounting guidance for
share-based payments.

(c) Drilling rig standby charges represent
fees paid in connection with the deferral of drilling associated with
contractually committed rigs and frac tank rentals.

(a) Net proceeds from the sale of Penn Virginia GP Holdings, L.P. (PVG)
units included in investing activities is attributable to the sale of
the final tranche of PVG units, which resulted in the loss of control
and deconsolidation of PVG from our financial statements. Net proceeds
from the sale of PVG units included in financing activities represents
proceeds received from sales of our ownership interests in PVG while we
still maintained control.

(a) Net income (loss) attributable to PVA, as adjusted, represents net
income (loss) attributable to PVA adjusted to exclude the effects of
non-cash changes in the fair value of derivatives, drilling rig standby
charges, impairments, restructuring costs, gains and losses on the sale
of assets, the gain on the sale of PVG (discontinued operations) and net
income of Penn Virginia Resource Partners, L.P. (PVR) allocated to
unvested PVR restricted units awarded as equity compensation that are
held until vesting. 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 income
(loss) attributable to PVA, 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 income attributable to PVA.

* Prior to the sale of PVG, these line items were combined for guidance
purposes and shown as 'Cash operating expenses' with the Corporate G&A
expenses reflected separately. With the sale of PVG, PVA will operate in
only one industry segment. As such, we believe that a more detailed
breakdown of these operating expenses, and presentation of consolidated
G&A, will provide more useful guidance information to investors.

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 the remainder of 2010 would increase or decrease by
approximately $10.1 million. In addition, we estimate that for every
$5.00 per barrel increase or decrease in the crude oil price, operating
income for 2010 would increase or decrease by approximately $1.5
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.

Penn Virginia Corporation

James W. Dean

Vice President,
Corporate Development

Ph: 610-687-7531

Fax: 610-687-3688

invest@pennvirginia.com