Penn Virginia Corporation Announces Fourth Quarter and Full-Year 2011 Results; Provides Operational Update and Initial Full-Year 2012 Guidance

Penn Virginia Corporation (NYSE: PVA) today reported financial and
operational results for the three months and twelve months ended
December 31, 2011 and provided initial full-year 2012 guidance.

Fourth Quarter 2011 Highlights

Fourth quarter 2011 results, as compared to fourth quarter 2010 results,
were as follows:

• 
  Product revenues from the sale of natural gas, crude oil and natural
  gas liquids (NGLs) of $77.4 million, or $7.20 ?per thousand cubic feet
  of natural gas equivalent (Mcfe), increases of 21 percent and 48
  percent, respectively, compared to $63.9 ?million, or $4.88 per Mcfe
  
• 
  Oil and NGL revenues of $53.9 million, or 70 percent of product
  revenues, an increase of 99 ?percent compared to $27.1 ?million, or 42
  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 $5.22 per Mcfe, an increase of 83
  percent compared to $2.85 per Mcfe
  
• 
  Operating loss of $37.1 ?million, compared to a loss of $25.0 million
  
• 
  Adjusted EBITDAX, a non-GAAP measure, of $62.2 million, an increase of
  34 percent compared to $46.6 million
  
• 
  Net loss from continuing operations of $27.9 million, or $0.61 per
  diluted share, compared to a loss of $24.8 ?million, or $0.54 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 $6.2 ?million, or $0.14 per diluted share, compared to a
  loss of $11.0 million, or $0.24 per diluted share
  
• 
  Oil and NGL production of 662 thousand barrels, or 37 ?percent of total
  equivalent production, an increase of 43 ?percent compared to 463
  thousand barrels, or 21 ?percent of total equivalent production
  

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

Recent operational highlights are as follows:

• 
  14 (11.7 net) Eagle Ford Shale wells have been completed and turned in
  line since our last report in November 2011, bringing the total to
  35 ?(29.2 ?net) producing Eagle Ford Shale wells to date, with an
  average peak gross production rate of approximately 1,000 ?barrels of
  oil equivalent (BOE) per day (BOEPD) per well
  
  
  • 
    To date, 26 wells have at least 30 days of production history and
    have had an initial 30-day average gross production rate of
    approximately 675 ?BOEPD per well.
    
• 
  Three rigs are currently drilling the 40^th through 42^nd
  Eagle Ford wells, with three wells in the process of being completed
  and one well waiting on completion (WOC).
  

• 
  Eagle Ford Shale production was approximately 9,800 (6,280 net) BOEPD
  at the end of January, with oil comprising approximately 89 ?percent,
  NGLs comprising approximately six percent and natural gas comprising
  approximately five 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
  approximately 31,400 (23,100 net) acres, with up to 190 well locations
  assuming down-spacing is successful on a majority of our acreage.
  
  
  • 
    The first well on the Lavaca County acreage is expected to spud
    late in the first quarter
    

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated,
'Fourth quarter 2011 operating results continued the positive trend of
improved margins due to increased oil production. Operating cash flows
and margins remained strong due to increasing oil production volumes,
continued high oil prices and generally lower operating expenses. Oil
and liquids revenues increased 99 ?percent over the prior year period and
comprised 70 ?percent of product revenues, resulting in an 83 percent
improvement in our gross operating margin per Mcfe of production. Oil
and liquids production increased 43 ?percent over the prior year quarter
and represented 37 percent of fourth quarter production. In 2012, we
expect oil and liquids to comprise approximately 78 percent of product
revenues and approximately 42 ?percent of production.

'Our improved financial results, achieved despite very weak gas prices,
were driven primarily by our oily Eagle Ford Shale play where we have
significantly increased our acreage and potential drilling locations
during 2011. Building on this success, we plan to devote approximately
85 percent of estimated 2012 capital expenditures to the Eagle Ford
Shale, drilling 31 ?(26.7 net) wells. At the same time, we intend to
reduce the outspend of cash flow. We are currently operating three rigs
in the Eagle Ford Shale, but will decrease the rig count to two to
reduce 2012 capital expenditures by approximately 30 ?percent compared to
2011. To further improve liquidity, we are also considering the sale of
some of our non-strategic assets. Despite the reduction in capital
expenditures, an approximate 21 to 24 percent decrease in pro forma gas
production and lower gas prices, we expect operating cash flows to
increase in 2012.?

Full-Year 2011 Consolidated Results

For the year ended December 31, 2011, we incurred an operating loss of
$155.4 million, which included impairment charges of $104.7 million,
compared to a loss in 2010 of $98.8 million, which included impairment
charges of $46.0 ?million. The adjusted net loss attributable to PVA,
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, was $47.7 ?million, or $1.04 per
diluted share, in 2011 compared to an adjusted loss of $32.7 million, or
$0.72 per diluted share, in 2010. The net loss from continuing
operations was $132.9 million, or $2.90 per diluted share, in 2011
compared to a loss of $65.3 million, or $1.43 ?per diluted share, in
2010, due primarily to the increase in operating loss, a $25.4 million
loss on the extinguishment of debt in 2011, a $26.3 million decrease in
derivatives income and a $4.6 ?million increase in interest and other
expenses. Pro forma to exclude production from the Mid-Continent assets
sold in August 2011 and the Gulf Coast assets sold in January 2010, oil
and gas production in 2011 was 44.2 Bcfe, compared to 43.6 Bcfe in 2010.
Year-end 2011 proved reserves were 883 ?Bcfe, compared to 903 Bcfe at
year-end 2011, pro forma to exclude year-end 2010 proved reserves from
the Mid-Continent assets sold in 2011.

Fourth Quarter 2011 Financial and Operational Results

Overview of Financial Results

The $37.1 million operating loss was $12.1 million higher than the
$25.0 ?million loss in the prior year quarter, due primarily to a $23.9
million increase in impairment expense, a $13.4 ?million decrease in
natural gas revenues and a $10.0 ?million increase in depreciation,
depletion and amortization (DD&A) expense. The effect of these items was
partially offset by a $26.8 million increase in oil and liquids
revenues, a $5.2 million decrease in total direct operating expenses, a
$3.0 ?million increase in gain on the sale of property associated with
the divestiture of approximately 2,500 ?acres of Marcellus acreage and a
$1.3 ?million decrease in exploration expense. Oil and NGL revenues were
$53.9 million in the fourth quarter of 2011, 99 ?percent higher than the
$27.1 ?million in the prior year quarter and 13 percent higher than the
$47.8 million in the third quarter of 2011. Oil and NGL revenues were
70 ?percent of product revenues in the fourth quarter of 2011, compared
to 42 percent in the prior year quarter and 58 percent in the third
quarter of 2011.

Pricing

Our fourth quarter 2011 realized oil price was $98.49 per barrel, 19
percent higher than the $82.84 ?per barrel price in the fourth quarter of
2010 and 13 percent higher than the $87.03 ?per barrel price in the third
quarter of 2011. Our fourth quarter 2011 realized NGL price was $45.46
per barrel, eight ?percent higher than the $42.15 ?per barrel price in the
fourth quarter of 2010 and five percent lower than the $48.00 per barrel
price in the third quarter of 2011. Our fourth quarter 2011 realized
natural gas price was $3.46 per thousand cubic feet (Mcf), three percent
lower than the $3.57 per Mcf price in the fourth quarter of 2010 and 18
percent lower than the $4.24 per Mcf price in the third quarter of 2011.
Adjusting for oil and gas hedges, our fourth quarter 2011 effective oil
price was $101.21 ?per barrel and our effective natural gas price was
$4.33 per Mcf, or increases of $2.72 per barrel and $0.87 per Mcf over
the realized prices.

Production

As shown in the table below, production in the fourth quarter of 2011
was 10.7 Bcfe, or 116.7 ?MMcfe per day, an 18 ?percent decrease compared
to 13.1 Bcfe, or 142.5 MMcfe per day, in the prior year quarter and a 10
percent decrease from 11.9 Bcfe, or 129.9 ?MMcfe per day, in the third
quarter of 2011. As a percentage of total equivalent production, oil and
NGL volumes were 37 ?percent in the fourth quarter of 2011, compared to
21 percent in the prior year quarter and 33 percent in the third quarter
of 2011. On a pro forma basis to exclude production from the
Mid-Continent assets sold in 2011, production in the prior year quarter
was 12.3 Bcfe, or 134.0 MMcfe per day. The pro forma decrease of 1.6
Bcfe, or 13 percent, was primarily the result of a 2.8 Bcfe, or 29
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, in the Granite Wash, partially offset by a 200 thousand
barrel (1.2 ?Bcfe), or 43 percent, increase in pro forma oil and NGL
production.

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

⁽²⁾ Includes production from the Mid-Continent assets sold in
2011.

⁽³⁾ Pro forma to exclude production from the Mid-Continent
assets sold in 2011.

Note - Numbers may not add due to rounding.

Operating Expenses

As discussed below, fourth quarter 2011 total direct operating expenses
decreased $5.2 million, or approximately 20 ?percent, to $21.3 ?million,
or $1.99 ?per Mcfe produced, compared to $26.5 million, or $2.02 per Mcfe
produced, in the fourth quarter of 2010 and $25.6 million, or $2.14 per
Mcfe produced, in the third quarter of 2011.

• 
  Lease operating expenses decreased by $1.1 million, or 13 percent, to
  $7.5 million, or $0.70 ?per Mcfe produced, from $8.6 million, or $0.66
  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. The unit cost increased slightly due to lower production
  volumes.
  
• 
  Gathering, processing and transportation expenses decreased by $0.1
  million, or three percent, to $3.9 ?million, or $0.36 per Mcfe
  produced, from $4.0 million, or $0.31 per Mcfe produced, in the prior
  year quarter resulting from lower production volumes, partially offset
  by higher processing costs associated with higher NGL production. The
  unit cost increased slightly due to lower production volumes.
  

• 
  Production and ad valorem taxes increased 95 percent to $2.4 ?million,
  or 3.1 percent of product revenues, from $1.2 ?million, or 1.9 percent
  of product revenues, in the prior year quarter resulting primarily
  from higher product revenues, as well as favorable tax adjustments
  during the prior year quarter.
  
• 
  General and administrative (G&A) expenses, excluding share-based
  compensation, decreased by $5.1 ?million, or 40 ?percent, to
  $7.6 ?million, or $0.71 per Mcfe produced, from $12.7 million, or $0.97
  per Mcfe produced, in the prior year quarter. This decrease reflects a
  $1.0 ?million decrease in restructuring costs and a $4.1 million
  reduction in recurring G&A expenses due primarily to lower employee
  headcount and lower support costs following restructuring actions
  taken during 2010 and 2011, including the sale of our Arkoma Basin
  assets in August 2011.
  

Exploration expense decreased $1.3 million to approximately
$10.7 ?million in the fourth quarter of 2011 from approximately
$12.0 ?million in the prior year quarter. The decrease was due primarily
to a $2.2 million decrease in dry-hole costs (zero in the fourth quarter
of 2011) and a $0.4 million decrease in drilling rig related charges,
partially offset by a $0.9 ?million increase in unproved property
amortization and a $0.5 million increase in geological and geophysical
costs.

DD&A expense increased by $10.0 million, or 25 percent, to
$49.3 ?million, or $4.59 per Mcfe produced, in the fourth quarter of 2011
from $39.3 million, or $3.00 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.

Impairment expense increased to $33.6 ?million in the fourth quarter of
2011 from $9.7 million in the prior year quarter due primarily to an
impairment of horizontal coalbed methane assets in Appalachia and
certain Selma Chalk assets in Mississippi.

Capital Expenditures

During the fourth quarter of 2011, oil and gas capital expenditures were
approximately $123 million, compared to $108 ?million in the fourth
quarter of 2010 and $114 million in the third quarter of 2011,
consisting of:

• 
  $111 million for drilling and completion activities, including 12 (9.7
  net) wells, all of which were successful
  
• 
  $8 million for seismic, pipeline, gathering and facilities
  
• 
  $4 million for leasehold acquisitions and other
  

2011 Proved Reserves

Proved reserves decreased to 883 Bcfe at year-end 2011 from 942 Bcfe at
year-2010 (903 ?Bcfe, pro forma to exclude 39 ?Bcfe of Mid-Continent
reserves sold in August 2011). Compared to year-end 2010, proved
developed reserves decreased to 49 percent from 53 percent, while proved
oil and NGL reserves increased to 24 percent from 21 ?percent.

During 2011, we added 119 Bcfe of proved reserves from extensions,
discoveries, purchases and other additions, including 65 Bcfe in the
Eagle Ford Shale, 40 Bcfe in the Marcellus Shale and 12 Bcfe in the
Selma Chalk. During 2011, we had 94 Bcfe of negative revisions,
including 45 Bcfe in the Granite Wash due primarily to previously
disclosed well interference issues, 28 Bcfe in East Texas and 17 Bcfe in
the Selma Chalk.

The decreases in the Securities & Exchange Commission (SEC)-assumed gas
price and gas proved reserves during 2011 were almost entirely offset by
the increases in SEC-assumed oil and NGL prices and oil and NGL proved
reserves, resulting in a 0.5 percent decrease in the PV-10 value
(present value of proved reserves, discounted at 10 percent) to $874
million at year-end 2011. Approximately 72 percent of the PV-10 value
was attributable to oil and NGLs, while 28 percent was attributable to
natural gas.

⁽⁴⁾ The estimated reserves, standardized measure and present
value were based on pricing assumptions for Henry Hub natural gas of
$4.12 per million British thermal units (MMBtu) and West Texas
Intermediate crude oil of $96.19 per barrel. These compare to prices of
$4.38 per MMBtu and $79.43 per barrel, respectively, at December 31,
2010. Both prices exclude the effects of hedged production and six Mcfe
is assumed to equal one barrel equivalent of liquids. MMBbls is defined
as one million barrels.

⁽⁵⁾ Reserve replacement ratio is defined as the sum of
reserve additions (reserve extensions, discoveries and other additions
plus revisions plus reserve purchases) divided by production for the
year. Reserve replacement cost per Mcfe is defined as capital
expenditures divided by reserve additions.

Operational Update

Eagle Ford Shale

During the fourth quarter of 2011, we drilled 11 (9.2 net) operated
wells in the Eagle Ford Shale, all of which were successful. We
currently have three rigs drilling our 40^th through 42^nd
wells, three wells that in the process of being completed, one well that
is WOC and 35 (29.2 net) wells that are producing. As shown in the table
below, our producing wells in the Eagle Ford Shale have had an average
peak gross production rate of approximately 1,000 BOEPD per well
(approximately 675 ?BOEPD 30-day average per well for the 26 of these
wells with sufficient production history). Eagle Ford Shale production
was approximately 9,800 (6,280 net) BOEPD at the end of January, with
oil comprising approximately 89 ?percent, NGLs comprising approximately
six percent and natural gas comprising approximately five percent.

⁽⁶⁾ Wellhead rates only; the natural gas associated with
these wells is yielding approximately 145 barrels of NGLs per million
cubic feet (MMcf).

⁽⁷⁾ The Cannonade Ranch #3H had been shut-in to address H₂S
production issues, but has recently been brought back online, while the
Munson Ranch #9H had a short lateral and only seven frac stages due to
faulting issues. As a result, production data for these two wells has
been excluded from the statistics.

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
approximately 31,400 (23,100 net) acres, with up to 190 ?well locations
assuming down-spacing is successful on a majority of our acreage. The
first well on the Lavaca County acreage is expected to spud late in the
first quarter. Our full-year 2012 guidance anticipates up to
31 ?(26.7 ?net) new wells in the Eagle Ford Shale. We continue efforts to
expand our Eagle Ford Shale position through additional leasing and
selective acquisitions.

Mid-Continent

During the fourth quarter of 2011, one (0.5 net) non-operated Granite
Wash well was drilled in the Mid-Continent. Our full-year 2012 guidance
includes up to seven ?(2.3 ?net) new Granite Wash wells. In addition,
during the first half of 2012, we plan to drill one (0.5 net) horizontal
well to test the Viola Limestone, which is an oil prospect.

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, a
  decrease of 1.2 to 4.2 Bcfe, or three to 10 ?percent, over full-year
  2011 production of 44.2 Bcfe, pro forma to exclude 2.3 Bcfe of
  production from divested assets
  
  
  • 
    The estimated 1.2 to 4.2 Bcfe pro forma decrease in production is
    due primarily to an expected 6.7 to 7.6 Bcf decrease in natural
    gas production and an expected 0.5 to 0.9 Bcfe (81 to 157 thousand
    barrels) decrease in NGL production from gas weighted plays,
    including the Granite Wash and Cotton Valley. These decreases are
    expected to be largely offset by an expected 4.3 to 6.0 Bcfe
    (722 ?thousand to approximately one million barrels) net increase
    in crude oil production
    
  • 
    Crude oil and NGL production is expected to increase by 26 to 42
    percent during 2012 over 2011 production levels (56 to 77 percent
    for crude oil, only). Crude oil and liquids are expected to
    comprise approximately 42 ?percent of total production during 2012,
    compared to 28 percent during 2011
    
• 
  Full-year 2012 product revenues are expected to be approximately $288
  to $319 million, compared to 2011 ?product revenues of $300.0 ?million,
  adjusted to reflect any premiums or discounts for quality, basis
  differentials and other adjustments, but exclude the impact of any
  hedges
  
  
  • 
    Crude oil and NGL product revenues are expected to be
    approximately 78 percent of total product revenues during 2012,
    compared to 54 percent during 2011
    
  • 
    2012 settlements of current commodity hedges are expected to
    results in cash receipts of approximately $25 million
    
  • 
    Currently, approximately 47 percent of estimated 2012 crude oil
    production and 32 percent of estimated 2012 natural gas production
    is hedged
    
• 
  Full-year 2012 Adjusted EBITDAX, a non-GAAP measure, is expected to be
  $200 to $240 million, compared to 2011 Adjusted EBITDAX of $219.5
  million
  
• 
  Full-year 2012 cash flow from operating activities is expected to be
  $175 to $205 million, including an anticipated $30 million income tax
  refund in the fourth quarter of 2012, compared to 2011 cash flow from
  operating activities of $144.7 million
  
• 
  Full-year 2012 capital expenditures are expected to be $300 to
  $325 ?million, a decrease of between approximately $121 and
  $146 ?million, or 27 to 33 percent, from 2011 capital expenditures of
  $445.6 million
  
  
  • 
    Approximately 85 percent of the 2012 capital expenditures are
    expected to be allocated to the Eagle Ford Shale and approximately
    eight percent to the Mid-Continent, with $270 to $280 million for
    drilling and completions, $20 to $25 million for lease
    acquisitions and $10 to $20 million for pipeline, gathering,
    seismic and facilities.
    

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 December 31, 2011, we had total debt with a carrying value of $697
million ($704 million aggregate principal amount), consisting of $294
million of 10.375 percent senior unsecured notes due 2016, $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 and $99 million of borrowings under our
revolving credit facility (the 'Revolver?). Net of cash and equivalents
of approximately $7 million, our indebtedness at December 31, 2011 was
approximately $690 ?million, which was 45 ?percent of book capitalization
and 3.1 times full-year 2011 Adjusted EBITDAX of $219.5 ?million.

We have no material debt maturities until 2016. Our business strategy
for 2012 requires capital expenditures in excess of our anticipated
operating cash flows as laid out in the table below.

⁽⁸⁾ Please see the Guidance Table included in this release
for guidance estimates for full-year 2012, which include production of
40.0 to 43.0 Bcfe (6.7 to 7.2 million BOE) and average benchmark prices
of $91.25 per barrel for crude oil, $42.62 per barrel for NGLs and $3.00
per MMBtu for natural gas, adjusted to reflect any premium or discount
for quality, basin differentials and other adjustments. In addition,
cash flows from operating activities include an estimated $30 million
cash income tax refund expected to be received in the fourth quarter of
2012.

Subject to the variability of commodity prices that impact our cash
flows from operating activities, anticipated timing of our capital
projects and unanticipated expenditures such as acquisitions, we plan to
fund our 2012 capital program with operating cash flows and borrowings
under the Revolver. We expect to supplement these sources of liquidity
with proceeds from the sale of non-core assets or, possibly, by
accessing the capital markets. There can be no assurance that such
actions would be successful, however, in which case we could further
reduce our 2012 planned capital expenditures.

In August 2011, we entered into the Revolver which matures in August
2016. The Revolver provides for a $300 ?million commitment amount and has
a borrowing base of $380 million. The borrowing base is re-determined
semi-annually, and the next re-determination is scheduled to occur
during April 2012. The primary assets supporting our borrowing base are
our proved developed reserves, approximately 77 percent of which are
natural gas. Due primarily to the significant decline in natural gas
prices that has continued into the first quarter of 2012 and despite the
increase in our oil reserves, we anticipate a potentially material
reduction in our borrowing base from its current level of $380 ?million.
Currently, we are unable to determine a meaningful potential range of
the reduction, due primarily to the fact that a number of determinative
variables are not known at this time; however, we do not anticipate a
material reduction to our current Revolver commitment of $300 ?million.
Accordingly, our current business plans anticipate us borrowing amounts
under the Revolver that are within the current commitment level of $300
million. Currently, we have approximately $14 million of cash on hand
and approximately $183 million of unused borrowing capacity under our
Revolver commitment, net of outstanding letters of credit of $1.4
million.

Interest expense increased to $14.4 ?million in the fourth quarter of
2011 from $13.5 ?million in the fourth quarter of 2010 ?due to higher
average levels of debt outstanding.

During the fourth quarter of 2011, derivatives loss was $4.2 ?million,
compared to derivatives loss of $2.5 ?million in the prior year quarter.
Fourth quarter 2011 cash settlements of derivatives resulted in net cash
receipts of $7.1 ?million, compared to $8.5 million of net cash receipts
in the prior year quarter.

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.

Explanation of Non-GAAP PV-10 Value

PV-10 Value is a non-GAAP financial measure under SEC regulations and
differs from the Standardized Measure of Discounted Future Net Cash
Flows (Standardized Measure) in that PV-10 Value is a pre-tax value,
while the Standardized Measure includes the effect of estimated future
income taxes, discounted at 10 percent. We believe that the PV-10 Value
is an important measure that can be used to evaluate the relative
significance of our oil and natural gas properties and that PV-10 Value
is widely used by security analysts and investors when evaluating oil
and gas companies. Because many factors that are unique to each
individual company impact the amount of future income taxes to be paid,
the use of a pre-tax measure enhances comparability of assets when
evaluating companies. The Standardized Measure at year-end 2011 of
$654.5 million, plus $219.9 million of present value of future income
tax discounted at 10 percent, is equal to the PV-10 Value of $874.4
million.

Fourth Quarter and Full-Year 2011 Financial and Operational Results
Conference Call

A conference call and webcast, during which management will discuss
fourth quarter and full-year 2011 financial and operational results, is
scheduled for Thursday, February 23, 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
4339698), 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 4339698. 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 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, 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; 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 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.

(a) Includes restructuring costs of approximately $0.7 million and $1.8
million and $2.4 million and $8.2 million for the three months and years
ended December 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.

(c) Attributable primarily to the repurchase in April 2011 of
approximately 98% of our 4.5% convertible senior subordinated notes due
2012.