Penn Virginia Corporation Announces First Quarter 2011 Results

Penn Virginia Corporation (NYSE: PVA) today reported financial and
operational results for the three months ended March 31, 2011 and
provided an update of full-year 2011 guidance.

First Quarter 2011 Highlights

First quarter 2011 results, as compared to first quarter 2010 results,
are as follows:

• 
  Production of 12.2 billion cubic feet of natural gas equivalent
  (Bcfe), or 135.2  million cubic feet of natural gas equivalent (MMcfe)
  per day, a 21 percent increase as compared to 10.0 Bcfe, or 111.6
  MMcfe per day, pro forma to exclude 0.3 Bcfe of production from Gulf
  Coast assets sold in January 2010;
  
• 
  Operating loss of $28.5  million, as compared to operating income of
  $0.1 million, due primarily to a $23.5 million increase in exploratory
  expense and a $4.8 million increase in depreciation, depletion and
  amortization (DD&A) expense;
  
• 
  Direct operating expenses of $30.9 million, or $2.54 per thousand
  cubic feet of natural gas equivalent (Mcfe) produced, as compared to
  $28.2  million, or $2.73 per Mcfe;
  
• 
  Adjusted EBITDAX, a non-GAAP (generally accepted accounting
  principles) measure defined on page eight of this release, of $44.1
  million as compared to $49.1 million;
  
• 
  Net loss from continuing operations of $26.3 million, or $0.58 per
  diluted share, as compared to net income from continuing operations of
  $10.8  million, or $0.24 per diluted share; and
  
• 
  Adjusted net loss attributable to PVA, a non-GAAP measure defined on
  page eight of this release, of $23.1  million, or $0.51 per diluted
  share, as compared to adjusted net income of $1.5 million, or $0.03
  per diluted share.
  

The operating loss and net loss from continuing operations in the first
quarter of 2011 included increases relative to the first quarter of 2010
in exploratory dry hole costs of $16.4 million in the Mid-Continent
region and unproved leasehold amortization expense of $5.5 million, due
to leasehold acquisitions primarily in the Marcellus and Eagle Ford
Shales during 2010.

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

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'In
late 2010 we made the strategic decision to shift our production and
reserve mix towards oil and natural gas liquids (NGLs) through a
reduction in natural gas drilling and an increase in drilling and
leasehold acquisitions in oil and liquids-rich play types. During the
first quarter of 2011, we continued to make progress in implementing
this strategy as we reported the first contributions from the oily Eagle
Ford Shale, a play in which we now have three operated rigs, are
currently drilling our seventh well, have just recently completed our
second and third wells and have expanded our position to approximately
13,000 net acres. Our initial well continues to outperform our original
expectations, still producing almost 500 barrels of oil and 300 Mcf of
wet gas per day after 80 days of production. The gas is currently being
flared until gathering facilities are constructed, after which this gas
will be processed. The gathering facilities are expected to be in place
by early June 2011.

'For full-year 2011, we expect oil and NGLs to contribute between 28 and
30 percent of total equivalent production, as compared to approximately
18 percent of 2010 total equivalent production, and we expect to exit
2011 with approximately 35  percent of fourth quarter total equivalent
production from oil and NGLs. Despite this transition from historical
investments in natural gas plays to primarily oil plays, we have kept
our full-year 2011 production guidance range of 50 to 54  Bcfe unchanged
as we expect significant increases in Eagle Ford Shale production during
the second half of the year.?

Mr. Whitehead continued, 'In the Marcellus Shale, we recently completed
our first two horizontal Marcellus Shale wells. We are continuing to
seek alternatives for our position in this promising but gassy and
capital-intensive play and may also monetize other non-core gas assets
and use the proceeds to expand our Eagle Ford Shale and other oil and
liquids-rich plays. We are pleased with the 2010 results from our
liquids-rich horizontal Cotton Valley wells and, given the possibility
of monetizing non-core gas assets during 2011, may use a portion of such
proceeds to recommence drilling of horizontal Cotton Valley wells.

'First quarter 2011 exploration results in the Mid-Continent were
disappointing as we have previously discussed and we expensed
approximately $16.4  million during the first quarter related to three
unsuccessful wells. Despite these exploratory setbacks, we were
otherwise pleased with our first quarter results, especially the
acceleration of our Eagle Ford drilling program.?

Mr. Whitehead concluded, 'With our strong financial condition and
liquidity, we are well-positioned to execute on our capital plans in
2011. During the final three quarters of 2011, approximately 56 percent
of our expected natural gas production is hedged at a weighted average
floor / swap price of $5.09 per MMBtu and approximately 22 percent of
our expected crude oil production is hedged at weighted average floor
and ceiling / swap prices of between approximately $94 and $106 per
barrel. In April 2011, we completed a $300 million offering of
7.25  percent senior unsecured notes due 2019, providing us with
low-cost, long-term capital.?

First Quarter 2011 Financial and Operational Results

The operating loss of $28.5 million was $28.6 million lower than the
operating income of $0.1  million in the prior year quarter, due
primarily to a $23.5 million increase in exploratory expense and a $4.8
million increase in DD&A expense. The $7.1 million decrease in natural
gas and other revenues and $1.0 million increase in other operating
expenses were largely offset by a $7.8 million increase in oil and NGL
revenues.

As shown in the table below, production in the first quarter of 2011 was
approximately 12.2 Bcfe, or 135.2  MMcfe per day, a 21  percent increase
as compared to 10.0 Bcfe, or 111.6 MMcfe per day, pro forma to exclude
0.3 Bcfe of production from Gulf Coast assets sold in January 2010
(reported production was 10.3 Bcfe, or 114.9 MMcfe per day), and a five
percent decrease from 13.1 Bcfe, or 142.5  MMcfe per day, in the fourth
quarter of 2010. As a percentage of total equivalent production, oil and
NGL volumes were 20  percent in the first quarter of 2011, as compared to
17 percent in the prior year period.

The year-over-year production increase was due to the effects of
significantly increased drilling activity during 2010, while the
sequential quarterly decrease was due to a reduction in natural gas
drilling and base production declines, as well as a lag in initial
production volumes from the Eagle Ford Shale due to completion delays
associated with the drilling of multiple wells from the same location.
Please see our separate operational update news release dated May 4,
2011 for a more detailed discussion of operations.

⁽¹⁾ Initial production from the Eagle Ford Shale commenced in
February 2011.

⁽²⁾ Pro forma to exclude Gulf Coast
assets sold in January 2010.

Note -
Numbers may not add due to rounding.

Our realized first quarter 2011 natural gas price was $4.23 per thousand
cubic feet (Mcf), 24 percent lower than the $5.60 per Mcf price in the
first quarter of 2010 and 19  percent higher than the $3.57 per Mcf price
in the fourth quarter of 2010. Our first quarter 2011 realized oil price
was $88.37 per barrel, 19 percent higher than the $74.44 per barrel
price in the first quarter of 2010 and seven percent higher than the
$82.84  per barrel price in the fourth quarter of 2010. Our first quarter
2011 realized NGL price was $45.11 per barrel, one  percent higher than
the $44.64 per barrel price in the first quarter of 2010 and seven
percent higher than the $42.15 per barrel price in the fourth quarter of
2010. Adjusting for oil and gas hedges, the first quarter 2011 effective
natural gas price was $4.95 per Mcf and our effective oil price was
$87.17 per barrel, or an increase of $0.72 per Mcf and decrease of $1.20
per barrel, respectively, over the realized prices.

As discussed below and due primarily to the 18 percent increase in
reported oil and gas production volumes, first quarter 2011 direct
operating expenses increased $2.7 million, or approximately 10 percent,
to $30.9  million, or $2.54 per Mcfe produced, as compared to $28.2
million, or $2.73 per Mcfe produced, in the first quarter of 2010.

• 
  Lease operating expenses increased by $1.5 million, or 18 percent, to
  $10.3 million, or $0.84  per Mcfe produced, from $8.7 million, or $0.85
  per Mcfe produced, resulting primarily from higher production volumes,
  as well as increased workover expense;
  
• 
  Gathering, processing and transportation expenses increased by $0.8
  million, or 25 percent, to $4.0  million, or $0.33 per Mcfe produced,
  from $3.2 million, or $0.31 per Mcfe produced, resulting primarily
  from higher production volumes and a change in the geographic
  distribution of production to the Mid-Continent region, which includes
  processing costs associated with Granite Wash wet gas production; and
  
• 
  Production and ad valorem taxes increased 19 percent to $5.1  million,
  or 7.5 percent of total product revenues, from $4.3  million, or 6.4
  percent of total product revenues, resulting primarily from higher
  production volumes and a decrease in natural gas as a percent of total
  equivalent production.
  

Exploration expense increased $23.5 million to $29.5  million in the
first quarter of 2011 from $6.0  million in the prior year quarter, due
primarily to a $16.4 million increase in dry hole costs attributable to
exploratory drilling in the Mid-Continent region, a $5.5 million
increase in unproved property amortization resulting from recent
acquisitions of unproved leasehold and a $1.4 million increase in
geological and geophysical costs.

DD&A expense increased by $4.8 million, or 16 percent, to $34.8  million,
or $2.86 per Mcfe produced, in the first quarter of 2011 from $30.0
million, or $2.90 per Mcfe produced, in the prior year quarter due
primarily to higher production volumes.

Full-Year 2011 Guidance Update

Full-year 2011 guidance highlights are as follows:

• 
  Full-year 2011 production guidance of 50.0 to 54.0 Bcfe, unchanged
  from previous guidance;
  
• 
  Full-year 2011 oil and NGL production guidance of between 28 and 30
  percent of total equivalent production, as compared to between 25 and
  27 percent of total equivalent production in previous guidance,
  including approximately 35  percent in the fourth quarter of 2011; and
  
• 
  Oil and gas capital expenditures guidance of $320 to $370 million, an
  increase of $20 to $25  million from previous guidance, due primarily
  to additional leasehold acquisitions and higher drilling costs
  associated with the Eagle Ford and Marcellus Shales.
  

As previously announced, we shifted an additional operated drilling rig
from the Mid-Continent to the Eagle Ford Shale, resulting in three
operated rigs currently drilling in the Eagle Ford Shale. Furthermore,
we have increased our acreage position in the Eagle Ford Shale to 12,700
net acres from our original position of 6,800 net acres in August 2010.
We expect production in the second quarter of 2011 to be consistent with
that of the first quarter, after which we expect production in the
second half of the year to be significantly higher due to the expected
impact of three rigs drilling in the Eagle Ford Shale from the second
quarter forward.

Please see the Guidance Table included in this release for guidance
estimates for full-year 2011. These estimates, including capital
expenditure plans, are meant to provide guidance only and are subject to
revision as our operating environment changes.

Capital Resources and Liquidity, Interest Expense and Impact of
Derivatives

As of March 31, 2011, we had outstanding borrowings of $509 million
(carrying value; $530 million aggregate principal amount), consisting of
$293 million (carrying value; $300 million aggregate principal amount)
of senior unsecured notes due 2016 and $216  million (carrying value;
$230 million aggregate principal amount) of convertible senior
subordinated notes due 2012, with no borrowings under our revolving
credit facility. Net of cash and equivalents of approximately $48
million, our indebtedness at March 31, 2011 was approximately
$460  million, or 33 percent of book capitalization. We currently have no
borrowings under our revolving credit facility.

In April 2011, we completed the offering of $300 million of 7.25 percent
senior unsecured notes due 2019. Approximately $241 million of the net
proceeds of $293 million were used to fund a tender offer for
approximately 98 percent of our convertible senior subordinated notes.
We expect to use the remaining net proceeds of approximately $52 million
to fund a portion of our capital expenditures program.

Interest expense decreased slightly to $13.5  million in the first
quarter of 2011 from $13.7  million in the first quarter of 2010 due
primarily to an increase in capitalized interest.

Due to fluctuations in commodity prices during the first quarter of
2011, derivatives income was $1.3  million as compared to derivatives
income of $29.9 million in the prior year quarter. First quarter 2011
cash settlements of derivatives resulted in net cash receipts of
$6.7  million, as compared to $8.4 million of net cash receipts in the
prior year quarter.

First Quarter 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
first quarter 2011 financial and operational results, is scheduled for
Thursday, May 5, 2011 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 1-866-630-9986 five to ten minutes before the scheduled
start of the conference call (use the passcode 7415900), 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 7415900. 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 development, exploration and production
of natural gas and oil in various domestic onshore regions including
Texas, Appalachia, the Mid-Continent 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 and oil; our
ability to develop, explore for, acquire and replace oil and gas
reserves and sustain production; any impairments, write-downs or
write-offs of our reserves or assets; the projected demand for and
supply of natural gas, natural gas liquids and oil; 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 costs 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
gas reserves; drilling and operating risks; our ability to compete
effectively against other independent and major oil and natural gas
companies; uncertainties related to expected benefits from acquisitions
of oil and natural gas properties; 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.

(a) Includes restructuring costs of less than $0.1 million and $1.5
million for the three months ended March 31, 2011 and 2010, respectively.

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

(a) Net proceeds from the sale of Penn Virginia GP Holdings, L.P. (PVG)
units represents proceeds received from sales of our ownership interests
in PVG while we still maintained control of PVG.

(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, restructuring costs,
gains and losses on the sale of assets 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.

(b) Adjusted EBITDAX represents net income (loss) from continuing
operations 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 and gains
and losses on the sale of assets. 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 income from continuing operations. Adjusted EBITDAX
represents EBITDAX as defined in our revolving credit facility, with the
exception of excluding distributions received from PVG and PVR, which
were $7.7 million in the first quarter of 2010 and zero in the first
quarter of 2011.

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 last three quarters of 2011 would increase or
decrease by approximately $28 million. In addition, we estimate that for
every $10.00 per barrel increase or decrease in the crude oil price,
operating income for the last three quarters of 2011 would increase or
decrease by approximately $15 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