Penn Virginia Corporation Announces Second Quarter 2011 Results

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

Second Quarter 2011 Highlights

Second quarter 2011 results, as compared to second quarter 2010 results,
were as follows:

• 
  Production of 11.7 billion cubic feet of natural gas equivalent
  (Bcfe), or 128.6  million cubic feet of natural gas equivalent (MMcfe)
  per day, a 12 percent increase as compared to 10.5 Bcfe, or 115.1
  MMcfe per day
  
  
  
  
  • 
    Oil and natural gas liquid (NGL) production increased to 472
    thousand barrels, or 24  percent of total equivalent production,
    from 224 thousand barrels, or 13  percent of total equivalent
    production
    
• 
  Total product revenues from the sale of natural gas, crude oil and
  NGLs of $73.0 million, or $6.24 per thousand cubic feet of natural gas
  equivalent (Mcfe), up 39 percent as compared to $52.4  million, or
  $5.00 per Mcfe
  
  
  
  
  • 
    Oil and NGL revenues increased by 156 percent to $34.7 million
    from $13.5  million
    
• 
  Total direct operating expenses of $28.8 million, or $2.47 per Mcfe, a
  decrease of $0.9 million as compared to $29.7  million, or $2.84 per
  Mcfe (a 13 percent decrease on a per-unit basis)
  
• 
  Operating loss of $80.7  million, an increase of $59.8 million as
  compared to a loss of $20.9 million, due to higher impairment and
  exploration expenses
  
• 
  Adjusted EBITDAX, a non-GAAP (generally accepted accounting
  principles) measure, of $47.5 million, an increase of $14.5 million,
  or 44 percent, as compared to $33.0 million
  
• 
  Net loss from continuing operations of $71.9 million, or $1.57 per
  diluted share, an increase of $50.8 million as compared to a net loss
  of $21.1  million, or $0.46 per diluted share, due primarily to the
  higher operating loss and a loss on the extinguishment of debt
  
• 
  Adjusted net loss attributable to PVA, a non-GAAP measure, of
  $11.9  million, or $0.26 per diluted share, as compared to a net loss
  of $9.4 million, or $0.21 per diluted share
  

The operating loss was $59.8 million greater than the prior year
quarter, due primarily to a $71.1  million impairment related to
non-core, primarily Arkoma Basin properties that we recently agreed to
sell and a $9.8 million increase in exploration expense. The net loss
from continuing operations was $50.8 million greater than the prior year
quarter due to the higher operating loss and a pretax $24.2  million loss
on the extinguishment of debt related to the previously announced
refinancing of our 4.5 percent convertible notes due in 2012.

Definitions of non-GAAP financial measures and reconciliations of these
non-GAAP financial measures to GAAP-based measures appear on page eight
of this release.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'Our
second quarter 2011 results demonstrate that we have made significant
progress in transforming PVA from a focus on natural gas to a new focus
on oil and NGLs, which has resulted in higher revenues and cash flows.
In the second quarter of 2011, oil and NGL revenues increased by
156  percent over the prior year quarter and were 31 percent higher than
the first quarter of 2011. In addition, oil and NGL revenues comprised
48 percent of total product revenues in the second quarter of 2011, as
compared to 26 percent in the prior year quarter and 39 percent in the
first quarter of 2011. We remain believers in natural gas over the
long-term, however, and retain our exposure to an eventual recovery in
the price of natural gas.

'The second quarter of 2011 is the first full quarter of contributions
from our oily Eagle Ford Shale properties, which had a significant
impact on our recurring financial results. We are operating three rigs
in the Eagle Ford Shale and are currently drilling our 15^th
through 17^th wells. We recently completed our 12^th
well, and we have two wells waiting on completion. Current production
from the Eagle Ford Shale is approximately 8,000 (5,000 net) barrels of
oil equivalent per day (BOEPD), and we expect to increase production
from this play to approximately 11,000 to 13,000 (7,000 to 8,000  net)
BOEPD by the end of 2011. We recently expanded our position to
approximately 13,900 net acres, which we feel is in the core of the
play, and increased our total location well inventory to up to 142
locations. In addition, we have our midstream facilities connected and
are experiencing no delays in obtaining completion or fracturing
services. In short, our early results in this play have been excellent.
We will continue to review leasing and acquisition opportunities to
expand our inventory of locations.

'We expect oil and NGLs to contribute between 30 and 32 percent of total
2011 equivalent production, as compared to approximately 18 percent of
2010 total equivalent production, and we expect to exit 2011 with
approximately 40 to 45  percent of fourth quarter total equivalent
production from oil and NGLs. As a result of this shift in production
mix towards higher-margin oil and NGLs, and despite the decreased
guidance for natural gas production, we expect second-half 2011
revenues, EBITDAX and other cash flows to increase and for that trend to
continue into 2012.?

Mr. Whitehead concluded, 'As disclosed in our separate news release
today, we entered into a new revolving credit facility which has a more
favorable leverage ratio through its maturity than our current credit
facility. This will help accommodate the expansion of our position in
the Eagle Ford Shale and, potentially, other oily plays. This new
leverage ratio covenant, together with the previously announced sale of
our primarily Arkoma Basin assets, places us in a solid liquidity
position to execute on our capital plans.?

Second Quarter 2011 Financial and Operational Results

The $80.7 million operating loss was $59.8 million higher than the
$20.9  million operating loss in the prior year quarter, due primarily to
a $69.9 million increase in impairment expense and a $9.8  million
increase in exploration expense. These expense increases were partially
offset by a $20.7 million, or 39 percent, increase in total product
revenues and a $0.9 million decrease in total direct operating expenses.
Oil and NGL revenues were $34.7 million in the second quarter of 2011,
156 percent higher than the $13.5 million in the prior year quarter and
31 percent higher than the $26.5 million in the first quarter of 2011.
Oil and NGL revenues were 48 percent of total product revenues in the
second quarter of 2011, as compared to 26 percent in the prior year
quarter and 39 percent in the first quarter of 2011.

As shown in the table below, production in the second quarter of 2011
was approximately 11.7 Bcfe, or 128.6  MMcfe per day, a 12  percent
increase as compared to 10.5 Bcfe, or 115.1 MMcfe per day, in the prior
year quarter and a five percent decrease from 12.2 Bcfe, or 135.2  MMcfe
per day, in the first quarter of 2011. As a percentage of total
equivalent production, oil and NGL volumes were 24  percent in the second
quarter of 2011, as compared to 13 percent in the prior year quarter and
20 percent in the first quarter of 2011.

The year-over-year production increase was due to our new Eagle Ford
Shale wells and contributions from 2010 drilling in the horizontal
Cotton Valley and Haynesville Shale plays. The 111 percent increase in
oil and NGL production as compared to the prior year quarter was due to
drilling activity in the Eagle Ford Shale and increased NGL volumes from
the Granite Wash. The sequential quarterly decrease in production was
attributable primarily to natural gas production declines, partially
offset by higher oil and NGL volumes in the Eagle Ford Shale. Please see
our separate operational update news release dated August 3, 2011 for a
more detailed discussion of operations.

Our second quarter 2011 realized natural gas price was $4.32 per
thousand cubic feet (Mcf), two percent higher than both the $4.25 per
Mcf price in the second quarter of 2010 and the $4.23 per Mcf price in
the first quarter of 2011. Our second quarter 2011 realized oil price
was $98.45 per barrel, 34 percent higher than the $73.64  per barrel
price in the second quarter of 2010 and 11 percent higher than the
$88.37  per barrel price in the first quarter of 2011. Our second quarter
2011 realized NGL price was $52.04 per barrel, 49  percent higher than
the $34.97  per barrel price in the second quarter of 2010 and 15 percent
higher than the $45.11 per barrel price in the first quarter of 2011.
Adjusting for oil and gas hedges, our second quarter 2011 effective
natural gas price was $4.80 per Mcf and our effective oil price was
$97.87  per barrel, or an increase of $0.48 per Mcf and a decrease of
$0.58 per barrel over the realized prices.

As discussed below, and despite the 12 percent increase in reported oil
and gas production volumes, second quarter 2011 total direct operating
expenses decreased $0.9 million, or approximately three percent, to
$28.8  million, or $2.47  per Mcfe produced, as compared to $29.7 million,
or $2.84 per Mcfe produced, in the second quarter of 2010.

• 
  Lease operating expenses increased by $1.6 million, or 18 percent, to
  $10.8 million, or $0.92  per Mcfe produced, from $9.2 million, or $0.87
  per Mcfe produced, due to higher maintenance, compression and workover
  costs
  
• 
  Gathering, processing and transportation expenses increased by $1.0
  million, or 29 percent, to $4.3  million, or $0.37 per Mcfe produced,
  from $3.3 million, or $0.32 per Mcfe produced, resulting from higher
  production volume and processing costs associated with NGLs, which
  comprised a significantly larger proportion of the total production
  volume in the current year quarter
  
• 
  Production and ad valorem taxes decreased nine percent to
  $2.8  million, or 3.9 percent of total product revenues, from
  $3.1  million, or 5.9 percent of total product revenues, resulting
  primarily from a production tax settlement in the Oklahoma
  
• 
  General and administrative expenses, excluding share-based
  compensation, decreased by $3.2 million, or 23  percent, to
  $10.9  million, or $0.94 per Mcfe produced, from $14.2 million, or
  $1.35 per Mcfe produced, due primarily to a $4.1 million decrease in
  restructuring costs from the prior period quarter
  

Exploration expense increased $9.8 million to approximately
$19.4  million in the second quarter of 2011 from $9.5  million in the
prior year quarter, due primarily to a $7.5 million increase in unproved
leasehold amortization expense and a $2.1 million increase in dry hole
costs related to a previously disclosed, unsuccessful vertical
exploratory well in the Texas panhandle.

Depreciation, depletion and amortization (DD&A) expense increased by
$0.9 million, or three percent, to $33.0  million, or $2.82 per Mcfe
produced, in the second quarter of 2011 from $32.1 million, or $3.06 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:

• 
  Production guidance of 48.5 to 50.5 Bcfe, a decrease of 1.5 to 3.5
  Bcfe from previous guidance of 50.0 to 54.0  Bcfe, due primarily to an
  approximate 3.6 Bcfe reduction in estimated Mid-Continent production
  following forecasting adjustments associated with the ongoing Granite
  Wash well communication issue related to stimulations (2.7 Bcfe),
  along with the previously announced sale of non-core producing assets,
  primarily in the Arkoma Basin (0.9 Bcfe). These decreases are expected
  to be partially offset by increased production from the Eagle Ford
  Shale due to very successful early results and shortened drilling times
  
  
  
  
  • 
    Oil and NGL production guidance of between 30 and 32 percent of
    total equivalent production, compared to between 28 and 30 percent
    of total equivalent production in previous guidance (approximately
    40 to 45  percent in the fourth quarter of 2011), due primarily to
    expected increases in oil and NGL volumes from the Eagle Ford Shale
    
• 
  Capital expenditures guidance of $360 to $380 million, an increase of
  between $10 and $40  million from previous guidance of $320 to $370
  million, due primarily to additional Eagle Ford Shale drilling,
  partially offset by decreased drilling in the Marcellus Shale
  

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 June 30, 2011, we had total debt with a carrying value of $598
million ($605 million aggregate principal amount), consisting of $293
million of 10.375 percent senior unsecured notes due 2016, $300 million
principal amount of 7.25  percent senior unsecured notes due 2019 and
$5  million principal amount of 4.5 percent convertible senior
subordinated notes due 2012. As of June 30, 2011, we had with no
borrowings under our revolving credit facility. Net of cash and
equivalents of approximately $31 million, our indebtedness at June 30,
2011 was approximately $567  million, or 39 percent of book
capitalization.

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 was used to fund a tender offer pursuant to
which we acquired approximately 98  percent of our 4.5 percent
convertible senior subordinated notes. The remaining net proceeds of
approximately $52 million are being used to fund a portion of our
capital expenditures program and for general corporate purposes.

Interest expense increased slightly to $14.1  million in the second
quarter of 2011 from $13.3  million in the second quarter of 2010 due to
higher average levels of debt outstanding, partially offset by lower
effective interest rates.

During the second quarter of 2011, derivatives income was $7.0  million,
as compared to derivatives loss of $0.6 million in the prior year
quarter. Second quarter 2011 cash settlements of derivatives resulted in
net cash receipts of $5.0  million, as compared to $9.1 million of net
cash receipts in the prior year quarter.

Second Quarter 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
second quarter 2011 financial and operational results, is scheduled for
Thursday, August 4, 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 5475077), 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 5475077. 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, NGLs 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, NGLs 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
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 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 regulation 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.

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