Penn Virginia Corporation Announces Second Quarter 2012 Results; Provides Updates of Operations and Full-Year 2012 Guidance

Penn Virginia Corporation (NYSE: PVA) today reported results for the
three months ended June 30, 2012 and provided an update of operations
and full-year 2012 guidance.

Second Quarter 2012 Highlights

Second quarter 2012 results compared to the second quarter of 2011 were
as follows:

• 
  Oil and natural gas liquids (NGLs) production of 799 thousand barrels
  of oil equivalent (MBOE), or 45 ?percent of total equivalent
  production, an increase of 69 ?percent compared to 472 MBOE, or
  24 ?percent of total equivalent production
  
• 
  Product revenues from the sale of natural gas, crude oil and NGLs of
  $76.2 million, or $7.16 ?per thousand cubic feet of natural gas
  equivalent (Mcfe), an increase of four percent compared to
  $73.0 ?million, or $6.24 per Mcfe (15 percent increase in per unit
  revenues)
  
• 
  Oil and NGL revenues of $65.9 million, or 86 percent of product
  revenues, an increase of 90 ?percent compared to $34.7 ?million, or 48
  percent of product revenues
  
• 
  Gross operating margin, a non-GAAP (generally accepted accounting
  principles) measure defined as total product revenues less total
  direct operating expenses, of $4.92 per Mcfe, an increase of 30
  percent compared to $3.78 per Mcfe
  
• 
  Adjusted EBITDAX, a non-GAAP measure, of $60.0 million, an increase of
  20 percent compared to $50.0 million
  
• 
  Operating loss of $38.0 ?million, including $28.6 million of impairment
  charges, compared to a loss of $80.7 million, including $71.1 million
  of impairment charges
  
• 
  Net loss of $5.6 million, or $0.12 per diluted share, compared to a
  loss of $71.9 ?million, or $1.57 per diluted share
  
• 
  Adjusted net loss, a non-GAAP measure which excludes the effects of
  changes in derivatives fair value, impairments, restructuring costs
  and other gains or losses that affect comparability to the prior year
  period, of $10.8 ?million, or $0.23 per diluted share, compared to a
  loss of $11.9 million, or $0.26 per diluted share
  

Definitions of non-GAAP financial measures and reconciliations of these
non-GAAP financial measures to GAAP-based measures appear later in this
release.

Recent operational highlights are as follows:

• 
  Seven (5.4 net) Eagle Ford Shale wells have been completed since early
  May, bringing the total to 51 ?(42.0 ?net) producing wells
  
  
  • 
    The average peak gross production rate per well for the 44 of
    these wells with full-length laterals was 1,001 ?barrels of oil
    equivalent (BOE) per day (BOEPD)
    
  • 
    The initial 30-day average gross production rate for 43 of these
    44 wells with sufficient production history was 657 ?BOEPD
    
• 
  We currently have two active rigs, one rig drilling our 53^rd
  well and the other rig in transit to drill our 54^th well,
  with one (0.6 net) well waiting on completion.
  
  
  • 
    A third drilling rig is expected to be added late in the third
    quarter of 2012
    
• 
  Our Eagle Ford Shale net production was approximately 6,550 BOEPD
  during the second quarter of 2012, with oil comprising approximately
  84 ?percent, NGLs approximately nine percent and natural gas
  approximately seven ?percent
  
• 
  The first five 'earning? wells on our 13,500-acre area of mutual
  interest (AMI) in Lavaca County, Texas have been drilled, with four
  wells completed and turned in line since April, one well waiting on
  completion and a rig in transit to drill the sixth and final earning
  well
  

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'We
are excited about our continuing success in the Eagle Ford Shale,
particularly our recent expansion into Lavaca County where early
drilling results are very promising. Our Eagle Ford Shale program has
driven an overall year-over-year increase of approximately 70% in oil
and NGLs production. In addition, second quarter oil and NGL revenues,
excluding hedge impacts, were more than six times our natural gas
revenue. We expect oil and NGLs to comprise approximately 84 percent of
product revenues and 47 percent of production in 2012. Building on this
success, we plan to devote over 90 percent of 2012 capital expenditures
to the Eagle Ford Shale and to add a third rig back into our Eagle Ford
Shale program late in the third quarter.

'To help fund our drilling program, we sold our Appalachian assets and
we have hedged approximately 67 percent of expected oil production and
32 percent of expected gas production in the second half of 2012 at
average prices of approximately $101 per barrel and $5.24 per MMBtu. Our
Board of Directors has also decided to discontinue our quarterly cash
dividend, which will add more than $10 million annually to our cash flow
available for reinvestment.

'We are optimistic about the future. We expect continued success in the
Eagle Ford Shale and, in light of the recent increase in natural gas
prices, we view our significant natural gas positions in East Texas,
Mississippi and the Granite Wash as having additional upside potential.?

Second Quarter 2012 Financial and Operational Results

Pricing

Our second quarter 2012 realized oil price of $102.14 per barrel was
four percent higher than the $98.45 ?per barrel price in the prior year
quarter. Our second quarter 2012 realized NGL price of $33.23 per barrel
was 36 ?percent lower than the $52.04 ?per barrel price in the prior year
quarter. Our second quarter 2012 realized natural gas price of $1.76 per
thousand cubic feet (Mcf) was 59 percent lower than the $4.32 per Mcf
price in the prior year quarter. Adjusting for oil and gas hedges, our
second quarter 2012 effective oil price was $102.03 ?per barrel and our
effective natural gas price was $2.72 per Mcf, or a decrease of $0.11
per barrel and an increase of $0.96 per Mcf over the realized prices.

Overview of Financial Results

The $38.0 million operating loss was $42.7 million, or 53 percent better
than the $80.7 ?million loss in the prior year quarter, due primarily to
a $31.2 million increase in oil and NGL revenues, a $42.5 ?million
decrease in impairments, a $10.0 ?million decrease in exploration expense
and a $5.0 million decrease in total direct operating expenses. The
positive effect of these items was partially offset by a $28.0 ?million
decrease in natural gas revenue and an $18.7 ?million increase in
depreciation, depletion and amortization (DD&A) expense. Oil and NGL
revenues were $65.9 ?million in the second quarter of 2012, 90 ?percent
higher than the $34.7 ?million in the prior year quarter. Oil and NGL
revenues were 86 ?percent of product revenues in the second quarter of
2012, compared to 48 percent in the prior year quarter.

Production

As shown in the table below, production in the second quarter of 2012
was 10.7 Bcfe, or 117.1 ?MMcfe per day, a nine ?percent decrease compared
to 11.7 Bcfe, or 128.6 MMcfe per day, in the prior year quarter. As a
percentage of total equivalent production, oil and NGL volumes were
45 ?percent in the second quarter of 2012 compared to 24 ?percent in the
prior year quarter. Oil production increased 161 percent from 219
thousand barrels (MBbls) in the prior year quarter to 572 MBbls in the
second quarter of 2012. On a pro forma basis, excluding production from
the Mid-Continent assets sold in 2011, production in the prior year
quarter was 11.1 Bcfe, or 122.3 MMcfe per day. The pro forma four
percent decrease was primarily the result of a 2.5 Bcfe, or 30 percent,
decrease in natural gas production due to reduced natural gas drilling
since mid-2010 in East Texas, Mississippi and, to a lesser extent, the
Granite Wash, partially offset by a 337 MBOE (2.0 ?Bcfe), or 73 percent,
increase in oil and NGL production.

Operating Expenses

Second quarter 2012 total direct operating expenses decreased $5.0
million, or approximately 17 ?percent, to $23.8 ?million, or $2.24 ?per
Mcfe produced, compared to $28.8 million, or $2.47 per Mcfe produced, in
the prior year quarter.

• 
  Lease operating expenses decreased by $1.5 million, or 14 percent, to
  $9.3 million, or $0.87 ?per Mcfe produced, from $10.8 million, or $0.92
  per Mcfe produced, in the prior year quarter due to lower repair and
  maintenance expenses, lower compression costs and the sale of the
  higher-cost Arkoma Basin properties in August 2011.
  
• 
  Gathering, processing and transportation expenses increased by
  approximately $0.1 million, or three percent, to $4.4 ?million, or
  $0.41 per Mcfe produced, from $4.3 million, or $0.37 per Mcfe
  produced, in the prior year quarter, despite lower overall production
  volumes, due primarily to higher pipeline transportation costs in the
  Appalachian region.
  
• 
  Production and ad valorem taxes decreased 109 percent to a credit of
  $0.3 ?million from $2.8 ?million of expense in the prior year quarter
  due primarily to Oklahoma severance tax rebates of $2.8 million
  attributable to horizontal and ultra-deep wells drilled from July 2009
  to June 2011 and lower natural gas prices.
  
• 
  General and administrative expenses, excluding share-based
  compensation, decreased by $0.5 ?million, or five ?percent, to
  $10.4 ?million, or $0.98 per Mcfe produced, from $10.9 million, or
  $0.94 per Mcfe produced, in the prior year quarter. This decrease was
  due primarily to lower employee headcount and lower support costs
  following restructuring actions taken during 2011, with the unit cost
  increasing due to lower gas production volumes.
  

Exploration expense decreased $10.0 million, or 52 percent, to
$9.4 ?million in the second quarter of 2012 from $19.4 ?million in the
prior year quarter. The decrease was due primarily to a $3.7 ?million
decrease in unproved property amortization, a $3.5 million decrease in
geological and geophysical costs and a $2.1 million decrease in dry-hole
costs (zero in the second quarter of 2012).

DD&A expense increased by $18.7 million, or 57 percent, to
$51.7 ?million, or $4.86 per Mcfe produced, in the second quarter of 2012
from $33.0 million, or $2.82 per Mcfe produced, in the prior year
quarter, due primarily to higher DD&A costs attributable to our Eagle
Ford Shale oil wells and reserve revisions associated with our gas
assets at year-end 2011.

Capital Expenditures

During the second quarter of 2012, capital expenditures were
approximately $92 million, compared to $105 ?million in the prior year
quarter, consisting of:

• 
  $80 million for drilling and completion activities
  
• 
  $5 million for pipeline, gathering, facilities and seismic
  
• 
  $7 million for leasehold acquisitions and other
  

Operational Update

Eagle Ford Shale

During the second quarter of 2012, we drilled eight (7.0 net) operated
wells in the Eagle Ford Shale, all of which were successful. We
currently have two active rigs, one rig drilling our 53^rd
well and the other rig in transit to drill our 54^th well,
with one (0.6 net) well waiting on completion and 51 ?(42.0 net)
producing wells. The average peak gross production rate per well for the
44 of these wells with full-length laterals was 1,001 ?BOEPD. The initial
30-day average gross production rate for 43 of these 44 wells with
sufficient production history was 657 ?BOEPD. Our Eagle Ford Shale
production was approximately 6,550 net BOEPD during the second quarter
of 2012, with oil comprising approximately 84 ?percent, NGLs
approximately nine percent and natural gas approximately seven percent.

In late 2011, we announced a 13,500 acre AMI with a major oil and gas
company in Lavaca County, Texas pursuant to which, during 2012, we can
earn a minimum of approximately 8,000 net acres. This would bring our
Eagle Ford Shale position in Gonzales and Lavaca Counties, Texas to a
minimum of approximately 36,700 (25,100 net) acres, with up to 250 total
well locations (51 of which are producing) assuming down-spacing is
successful on a majority of our acreage.

The first four wells on the Lavaca County acreage (Effenberger #1H, Vana
#1H, Schacherl #1H and Sralla #1H) have been completed and turned in
line over the past few months. All of these wells have met or exceeded
our expectations with the two most recent wells being the Schacherl #1H
(22 frac stages and lateral length of approximately 5,450 feet;
previously reported), having a peak gross rate of 1,277 ?BOEPD of
wellhead volumes, and the Sralla #1H (18 frac stages and lateral length
of approximately 4,450 feet), having a peak gross rate of 827 BOEPD of
wellhead volumes. The Lavaca wells thus far and most of our recent
Gonzales wells are significantly choked initially, consistent with our
belief that restricting early rates will result in a shallower decline
profile and potentially higher recoverable reserves. Based on historical
production data, we estimate Gonzales County Eagle Ford Shale wells will
have gross reserves of approximately 400 MBOE and Lavaca County Eagle
Ford Shale wells will have gross reserves of approximately 500 ?MBOE. The
fifth well, the McCreary #1H has been drilled and is waiting on
completion, while the sixth 'earning? well in Lavaca County, the
Pavlicek #1H, will spud soon.

Our full-year 2012 guidance anticipates 33 ?(25.6 ?net) new wells in the
Eagle Ford Shale, including the wells drilled during the first half of
2012 and the impact of a third drilling rig to be added by the end of
the third quarter. Efforts continue to expand our Eagle Ford Shale
position through additional leasing and selective acquisitions.

Mid-Continent

During the second quarter of 2012, we drilled one (0.5 net) non-operated
well in the Granite Wash, which was successful. As previously discussed,
we are currently drilling our first horizontal Viola Lime well in
Jefferson County, Oklahoma with results expected to be known later in
the third quarter. The Viola Lime is a carbonate formation at a depth of
approximately 7,000 feet that is believed to be oil-productive based on
offsetting vertical production. We have an acreage position of
approximately 9,600 net acres which may be prospective in this play.

Full-Year 2012 Guidance

Full-year 2012 guidance highlights are as follows:

• 
  Full-year 2012 production is expected to be approximately 37 to 40
  Bcfe, a reduction compared to 40 to 43 ?Bcfe of previous guidance due
  primarily to the sale of producing assets in Appalachia which were
  expected to contribute approximately 3 Bcfe of production in the last
  five months of 2012
  
  
  • 
    Crude oil and NGLs are expected to comprise approximately
    47 ?percent of total production during 2012, compared to previous
    guidance of approximately 43 percent, due primarily to the
    Appalachian asset sale
    
• 
  Full-year 2012 product revenues are expected to be approximately $284
  to $303 million, compared to $292 to $316 million of previous
  guidance, excluding the impact of our hedges, due primarily to the
  Appalachian asset sale, partially offset by higher expected crude oil
  volumes
  
  
  • 
    Crude oil and NGL product revenues are expected to be
    approximately 84 percent of total product revenues
    
  • 
    Approximately 67 percent of estimated crude oil production volumes
    and 32 percent of estimated natural gas production volumes are
    hedged over the remaining two quarters of 2012 at weighted average
    prices of $100.80 per barrel and $5.24 per MMBtu
    
  • 
    Full-year 2012 settlements of current commodity hedges are
    expected to result in cash receipts of approximately $31 ?million,
    approximately $14 million of which was received during the first
    half of 2012
    
• 
  Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be
  $225 to $245 million, compared to previous guidance of $220 to $240
  million, due to lower cash costs and higher Eagle Ford Shale margins
  
• 
  Full-year 2012 capital expenditures are expected to be $300 to
  $325 ?million, unchanged from previous guidance, despite the expected
  increase in Eagle Ford Shale drilling activity during the fourth
  quarter of 2012
  
  
  • 
    As a result of recent liquidity enhancing actions we have taken as
    well as the initial success we have achieved in Lavaca County, we
    expect to add a third rig in the Eagle Ford Shale by late in the
    third quarter of 2012
    
  • 
    Approximately 92 percent of 2012 capital expenditures are expected
    to be allocated to the Eagle Ford Shale and approximately seven
    percent to the Mid-Continent
    

Please see the Guidance Table included in this release for guidance
estimates for full-year 2012. These estimates are meant to provide
guidance only and are subject to revision as our operating environment
changes.

Capital Resources and Liquidity

As of June 30, 2012, we had total debt with a carrying value of
approximately $779 million ($785 million aggregate principal amount),
consisting of $294 million of 10.375 percent senior unsecured notes due
2016 ($300 million principal amount), $300 million principal amount of
7.25 ?percent senior unsecured notes due 2019, approximately $5 ?million
principal amount of 4.5 ?percent convertible senior subordinated notes
due in November 2012 (classified as a current liability) and $180
million of borrowings under our revolving credit facility (Revolver).
Our indebtedness at June 30, 2012 was approximately 49 ?percent of book
capitalization and 3.1 times the latest twelve months′ Adjusted EBITDAX
of $253 ?million. As a result of the sale of Appalachian assets, pro
forma debt-to-Adjusted EBITDAX was approximately 2.9 ?times.

We have no material debt maturities until 2016. Our capital expenditures
for the second half of 2012 will be funded by operating cash flows, the
proceeds from the sale of our Appalachian assets and borrowings under
the Revolver.

Closing of the Sale of Appalachian Assets

On July 31, 2012, we closed the previously announced cash sale of our
Appalachian assets, with the exception of the Marcellus Shale, for $100
million, subject to customary closing adjustments. We intend to use the
net proceeds from this sale to partially fund our 2012 capital
expenditure plan, as well as for general corporate purposes. In
connection with the sale, we have recognized an impairment charge of
$28.6 million and, during the third quarter of 2012, we expect
additional charges for firm transportation as well as charges related to
the planned closing of our office in Canonsburg, Pennsylvania.

Discontinuation of Dividend

As part of our plan to improve liquidity and help fund our Eagle Ford
Shale drilling program, our Board of Directors has discontinued the
quarterly cash dividend on shares of our common stock.

Explanation of Non-GAAP Gross Operating Margin per Mcfe

Gross operating margin is a non-GAAP financial measure under SEC
regulations which represents total product revenues less total direct
operating expenses. Gross operating margin per Mcfe is equal to gross
operating margin divided by total natural gas, crude oil and NGL
production. Gross operating margin is not adjusted for the impact of
hedges. We believe that gross operating margin per Mcfe 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 2012 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
second quarter 2012 financial and operational results, is scheduled for
Thursday, August 2, 2012 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 10 minutes before the scheduled
start of the conference call (use the passcode 4082934), 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 4082934. 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 oil, NGLs and natural gas; our ability to develop,
explore for, acquire and replace oil and 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 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.

(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 $0.6 million attributable to these awards is
included in both the three and six months ended June 30, 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.

(a) Net loss, as adjusted, represents the net loss adjusted to exclude
the effects of non-cash changes in the fair value of derivatives,
impairments, restructuring costs, net gains and losses on the sale of
assets and loss on the extinguishment of debt. 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, 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, impairments, net gains and losses on the sale of
assets and loss on the extinguishment of debt. 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.

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 2012 would increase or decrease by
approximately $9 million. In addition, we estimate that for every $10.00
per barrel increase or decrease in the crude oil price, operating income
for the remainder of 2012 would increase or decrease by approximately
$11 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

610-687-7531

Fax: 610-687-3688

invest@pennvirginia.com