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

Penn Virginia Corporation (NYSE: PVA) today reported financial and
operational results for the three months ended March 31, 2012 and
provided an update of full-year 2012 guidance.

First Quarter 2012 Highlights

First quarter 2012 results, as compared to first quarter 2011 results,
were as follows:

• 
  Oil and natural gas liquids (NGLs) production of 763 thousand barrels
  of oil equivalent (MBOE), or 42 ?percent of total equivalent
  production, an increase of 87 ?percent compared to 408 MBOE, or
  20 ?percent of total equivalent production
  
• 
  Product revenues from the sale of natural gas, crude oil and NGLs of
  $82.7 million, or $7.60 ?per thousand cubic feet of natural gas
  equivalent (Mcfe), an increase of 22 percent compared to
  $67.7 ?million, or $5.56 per Mcfe (37 percent increase in per unit
  revenues)
  
• 
  Oil and NGL revenues of $67.8 million, or 82 percent of product
  revenues, an increase of 156 ?percent compared to $26.5 ?million, or 39
  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 $5.08 per Mcfe, an increase of 68
  percent compared to $3.02 per Mcfe
  
• 
  Adjusted EBITDAX, a non-GAAP measure, of $64.2 million, an increase of
  46 percent compared to $44.1 million
  
• 
  Operating loss of $3.4 ?million compared to a loss of $28.5 million
  
• 
  Net loss of $11.9 million, or $0.26 per diluted share, compared to a
  loss of $26.3 ?million, or $0.58 per diluted share
  
• 
  Adjusted net loss, a non-GAAP measure which excludes the effects of
  changes in derivatives fair value, restructuring costs and other gains
  or losses that affect comparability to the prior year period, of
  $7.1 ?million, or $0.15 per diluted share, compared to a loss of $23.1
  million, or $0.51 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:

• 
  10 (8.3 net) Eagle Ford Shale wells have been completed since the
  middle of February, bringing the total to 44 ?(36.6 ?net) producing
  Eagle Ford Shale wells.
  
  
  • 
    The average peak gross production rate per well for 40 of these
    wells, which had full-length laterals, was approximately
    1,000 ?barrels of oil equivalent (BOE) per day (BOEPD)
    
  • 
    The initial 30-day average gross production rate for 35 of these
    40 wells with sufficient production history was approximately
    650 ?BOEPD
    
• 
  Two drilling rigs are currently drilling the 46^th and 47^th
  Eagle Ford Shale wells, with one well waiting on completion (WOC)
  
• 
  Eagle Ford Shale production was approximately 9,200 (5,800 net) BOEPD
  during the first quarter of 2012, with oil comprising approximately
  88 ?percent, NGLs approximately six percent and natural gas
  approximately six percent
  
• 
  The first two 'earning? wells on our 13,500-acre area of mutual
  interest (AMI) in Lavaca County, Texas were completed and turned in
  line during April, with the third well currently being drilled
  

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'Our
successful transition from being predominantly a natural gas producer to
being a more significant oil and NGL producer is clearly benefiting us,
as evidenced by our much improved first quarter results. Oil and liquids
production increased 87 percent over the prior year quarter and 15
percent from the fourth quarter of 2011. During the quarter, oil
revenues alone were nearly four times natural gas revenues, excluding
the impact of our hedges, and we expect oil and liquids to comprise
approximately 84 ?percent of product revenues and approximately
43 ?percent of production in 2012. Our Eagle Ford Shale play, which has
driven this oily transformation, has grown significantly over the past
18 months, and our recent early success in Lavaca County de-risks a
portion of this acreage with the potential for drilling-related proved
reserve additions as the year progresses.?

Mr. Whitehead added, 'Building on this success, we currently plan to
devote approximately 89 percent of estimated 2012 capital expenditures
to the Eagle Ford Shale. Consistent with our previously announced plan
to sell assets and to further improve liquidity, we have commenced a
sale process for our largely non-operated and liquids-rich assets in the
Mid-Continent region, which primarily consist of our Granite Wash
properties. In addition, we continue to hedge our oil position and
currently have approximately 70 percent of our anticipated oil
production hedged for the final three quarters of 2012 at an average
price of approximately $102 per barrel.?

First Quarter 2012 Financial and Operational Results

Overview of Financial Results

The $3.4 million operating loss was $25.1 million, or 88 percent, lower
than the $28.5 ?million loss in the prior year quarter, due primarily to
a $41.3 million increase in oil and liquids revenues, a $21.6 ?million
decrease in exploration expense and a $3.5 million decrease in total
direct operating expenses. The positive effect of these items was
partially offset by a $26.3 ?million decrease in natural gas revenues and
a $16.0 ?million increase in depreciation, depletion and amortization
(DD&A) expense. Oil and NGL revenues were $67.8 million in the first
quarter of 2012, 156 ?percent higher than the $26.5 ?million in the prior
year quarter and 26 percent higher than the $53.9 million in the fourth
quarter of 2011. Oil and NGL revenues were 82 ?percent of product
revenues in the first quarter of 2012, compared to 39 percent in the
prior year quarter and 70 percent in the fourth quarter of 2011.

Pricing

Our first quarter 2012 realized oil price of $107.05 per barrel was 21
percent higher than the $88.37 ?per barrel price in the prior year
quarter and nine percent higher than the $98.49 ?per barrel price in the
fourth quarter of 2011. Our first quarter 2012 realized NGL price of
$42.24 per barrel was six ?percent lower than the $45.11 ?per barrel price
in the prior year quarter and seven percent lower than the $45.46 per
barrel price in the fourth quarter of 2011. Our first quarter 2012
realized natural gas price of $2.37 per thousand cubic feet (Mcf) was 44
percent lower than the $4.23 per Mcf price in the prior year quarter and
32 percent lower than the $3.46 per Mcf price in the fourth quarter of
2011. Adjusting for oil and gas hedges, our first quarter 2012 effective
oil price was $106.85 ?per barrel and our effective natural gas price was
$3.65 per Mcf, or a decrease of $0.20 per barrel and an increase of
$1.28 per Mcf over the realized prices.

Production

As shown in the table below, production in the first quarter of 2012 was
10.9 Bcfe, or 119.5 ?MMcfe per day, a 12 ?percent decrease compared to
12.2 Bcfe, or 135.2 MMcfe per day, in the prior year quarter and a two
percent increase from 10.7 Bcfe, or 116.7 ?MMcfe per day, in the fourth
quarter of 2011. As a percentage of total equivalent production, oil and
NGL volumes were 42 ?percent in the first quarter of 2012 compared to 20
percent in the prior year quarter and 37 percent in the fourth quarter
of 2011. Oil production increased 192 percent from 188 thousand barrels
(MBbls) in the prior year quarter to 549 MBbls in the first 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 11.5 Bcfe,
or 127.9 MMcfe per day. The pro forma decrease of 0.6 Bcfe, or six
percent, was primarily the result of a 2.8 Bcfe, or 31 percent, decrease
in pro forma 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 362 MBOE (2.2 ?Bcfe), or 90 percent,
increase in pro forma oil and NGL production.

Note - Numbers may not add due to rounding.

Operating Expenses

First quarter 2012 total direct operating expenses decreased $3.5
million, or approximately 11 ?percent, to $27.4 ?million, or $2.52 ?per
Mcfe produced, compared to $30.9 million, or $2.54 per Mcfe produced, in
the prior year quarter.

• 
  Lease operating expenses decreased by $1.1 million, or 11 percent, to
  $9.2 million, or $0.84 ?per Mcfe produced, from $10.3 million, or $0.84
  per Mcfe produced, in the prior year quarter due to lower production
  volumes as well as the sale of higher-cost Arkoma Basin properties in
  August 2011. Despite the decrease in costs, the unit cost was flat due
  to lower production volumes.
  
• 
  Gathering, processing and transportation expenses increased by
  approximately $0.2 million, or three percent, to $4.2 ?million, or
  $0.38 per Mcfe produced, from $4.0 million, or $0.33 per Mcfe
  produced, in the prior year quarter, despite lower overall production
  volumes, due primarily to firm transportation costs in the Appalachian
  region and a prior-period adjustment related to gathering volumes in
  the Mid-Continent.
  
• 
  Production and ad valorem taxes decreased 29 percent to $3.6 ?million,
  or 4.3 percent of product revenues, from $5.1 ?million, or 7.5 percent
  of product revenues, in the prior year quarter resulting from lower
  natural gas prices and lower severance tax rates for certain wells in
  Texas and Oklahoma.
  
• 
  General and administrative (G&A) expenses, excluding share-based
  compensation, decreased by $1.0 ?million, or nine ?percent, to
  $10.5 ?million, or $0.97 per Mcfe produced, from $11.5 million, or
  $0.95 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.
  

Exploration expense decreased $21.5 million, or 73 percent, to
$8.0 ?million in the first quarter of 2012 from $29.5 ?million in the
prior year quarter. The decrease was due primarily to a $16.4 million
decrease in dry-hole costs (zero in the first quarter of 2012), a
$2.4 ?million decrease in unproved property amortization and a $2.2
million decrease in geological and geophysical costs.

DD&A expense increased by $16.0 million, or 46 percent, to
$50.8 ?million, or $4.67 per Mcfe produced, in the first quarter of 2012
from $34.8 million, or $2.86 per Mcfe produced, in the prior year
quarter, due primarily to higher DD&A costs attributable to our Eagle
Ford Shale oil wells, which is typical for this and other oily plays, as
well as downward revisions in proved reserves located primarily in the
Granite Wash, East Texas and Mississippi at year-end 2011.

Capital Expenditures

During the first quarter of 2012, capital expenditures were
approximately $90 million, compared to $104 ?million in the prior year
quarter and $123 million in the fourth quarter of 2011, consisting of:

• 
  $83 million for drilling and completion activities, including 11 (9.4
  net) wells, all of which were successful
  
• 
  $3 million for seismic, pipeline, gathering and facilities
  
• 
  $4 million for leasehold acquisitions and other
  

Operational Update

Eagle Ford Shale

During the first quarter of 2012, we drilled 11 (9.4 net) operated wells
in the Eagle Ford Shale, all of which were successful. We currently have
two rigs drilling our 46^th and 47^th wells, one
well that is WOC and 44 (36.6 net) wells that are producing. As shown in
the table below, the average peak gross production rate per well for 40
of these wells which had full-length laterals was approximately
1,000 ?BOEPD. The initial 30-day average gross production rate for 35 of
these 40 wells with sufficient production history was approximately
650 ?BOEPD. Eagle Ford Shale production was approximately 9,200 (5,800
net) BOEPD during the first quarter of 2012, with oil comprising
approximately 88 ?percent, NGLs approximately six percent and natural gas
approximately six 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 31,400 (23,100 net) acres, with up to 190 total
well locations assuming down-spacing is successful on a majority of our
acreage.

The first two wells on the Lavaca County acreage (Effenberger #1H and
Vana #1H) were completed and turned in line during April 2012. Both
wells have met or exceeded our expectations with the Effenberger #1H (20
frac stages and lateral length of approximately 5,000 feet) averaging
922 BOEPD of wellhead volumes over its first nine days of production (90
percent oil and 10 percent wet gas) and the Vana #1H (13 frac stages and
lateral length of approximately 3,200 feet) averaging 709 ?BOEPD of
wellhead volumes over its first five days of production (94 percent oil
and six percent wet gas). The lateral length of the Vana #1H well was
less than expected by approximately 1,600 feet due to an issue with
getting casing to the total depth drilled. Taking into account the
lateral lengths, both wells appear to have similar production
characteristics during the initial flowback of frac fluids and are
comparable to well results experienced in nearby Gonzales County. Both
wells are significantly choked with the flowing pressure on the
Effenberger #1H well at the end of the nine days of approximately 3,450
pounds per square inch (psi) and the flowing pressure on the Vana #1H
well at the end of the five days of approximately 2,300 psi, as the
recovery of fluid continues. A third well in Lavaca County (Schacherl
#1H) is currently being drilled, with three additional wells expected to
be drilled during 2012.

Our full-year 2012 guidance anticipates 32 ?(27.6 ?net) new wells in the
Eagle Ford Shale, including the wells drilled during the first quarter
of 2012. Efforts continue to expand our Eagle Ford Shale position
through additional leasing and selective acquisitions.

Full-Year 2012 Guidance

Full-year 2012 guidance highlights are as follows:

• 
  Full-year 2012 production is expected to be 40.0 to 43.0 Bcfe,
  unchanged from previous guidance
  
  
  • 
    Crude oil and liquids are expected to comprise approximately
    43 ?percent of total production during 2012
    
• 
  Full-year 2012 product revenues are expected to be $292 to $316
  million, compared to $288 to $319 million of previous guidance,
  excluding the impact of our hedges
  
  
  • 
    Crude oil and NGL product revenues are expected to be
    approximately 84 percent of total product revenues during 2012
    
  • 
    Approximately 70 percent of estimated crude oil production volumes
    and 25 percent of estimated natural gas production volumes are
    hedged over the remaining three quarters of 2012 at weighted
    average prices of $102.21 per barrel and $5.27 per Mcf,
    respectively
    
  • 
    2012 settlements of current commodity hedges are expected to
    result in cash receipts of approximately $28 ?million
    
• 
  Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be
  $220 to $240 million, compared to previous guidance of $200 to $240
  million
  
• 
  Full-year 2012 cash flow from operating activities is expected to be
  $185 to $205 million, compared to previous guidance of $175 to $205
  million (both ranges include an anticipated $30 million income tax
  refund in the fourth quarter of 2012)
  
• 
  Full-year 2012 capital expenditures are expected to be $300 to
  $325 ?million, unchanged from previous guidance
  
  
  • 
    Approximately 89 percent of the 2012 capital expenditures are
    expected to be allocated to the Eagle Ford Shale and approximately
    four 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, Interest Expense and Impact of
Derivatives

As of March 31, 2012, we had total debt with a carrying value of
approximately $718 million ($724 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, $5 ?million principal
amount of 4.5 ?percent convertible senior subordinated notes due 2012
(classified as a current liability) and $119 million of borrowings under
our revolving credit facility (Revolver). Our indebtedness at March 31,
2012 was approximately 46 ?percent of book capitalization and 3.0 times
the latest twelve months′ Adjusted EBITDAX of $242.7 ?million, a
reduction from 3.2 times at year-end 2011.

We have no material debt maturities until 2016. Our business strategy
for 2012 requires capital expenditures in excess of our anticipated
operating cash flows, although within the Revolver′s borrowing base, as
shown in the table below.

We plan to fund our 2012 capital program with operating cash flows,
proceeds from asset sales and borrowings under the Revolver.

Borrowing Base Redetermination

In August 2011, we entered into the Revolver, which matures in August
2016. The Revolver provided for a $300 ?million commitment amount and
initial borrowing base of $380 million. Following the semi-annual
redetermination in April 2012 and as a result of decreased natural gas
prices, the borrowing base was lowered to $300 million, which is at the
upper end of our previously disclosed expectations. Our business plan
anticipates us borrowing amounts under the Revolver during the remainder
of 2012 that are within this redetermined borrowing base. As of April
30, 2012, we had approximately $22 million of cash on hand and
approximately $151 ?million of unused borrowing capacity under the
Revolver, net of outstanding letters of credit of $1.7 ?million.

Planned Asset Sale

We expect to reduce our indebtedness and supplement liquidity under the
Revolver with proceeds from the sale of non-core assets. We recently
engaged a financial advisor to assist us in the sale of the majority of
our remaining Mid-Continent assets. The sales process for these
liquids-rich and largely non-operated properties has commenced. The
properties anticipated to be sold include our Granite Wash production
and reserves, as well as a few exploratory prospects. However, we will
retain our Viola Limestone prospect acreage, which we expect to drill
late in the second quarter of this year. Based on internal estimates,
the properties to be divested have proved reserves of approximately 123
Bcfe, 46 ?percent of which are NGLs and oil, and 81 gross remaining
drilling locations. First quarter 2012 production for these assets was
23.6 ?MMcfe per day, 48 percent of which was NGLs and oil. No assurances
can be given that a sale will be completed or as to the timing of or the
net proceeds from such a sale.

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.

First Quarter 2012 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss
first quarter 2012 financial and operational results, is scheduled for
Thursday, May 3, 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 8452642), 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 8452642. 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; 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 natural gas,
natural gas liquids and oil; reductions in the borrowing base under our
Revolver; 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) Our 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. Share-based compensation
expense related to liability-classified awards payable in cash is
included in general and administrative expense.

(a) The convertible notes are due in November 2012 and are included in
current liabilities.

(a) Net loss, as adjusted, represents the net loss adjusted to exclude
the effects of non-cash changes in the fair value of derivatives,
restructuring costs, and net 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. 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, and net 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 loss. Adjusted EBITDAX represents
EBITDAX as defined in our revolving credit facility.