Penn Virginia Corporation Announces Fourth Quarter and Full-Year 2012 Results; Provides Initial 2013 Guidance

Penn Virginia Corporation (NYSE: PVA) today reported financial results
for the three and twelve months ended December 31, 2012 and provided
initial 2013 guidance.

Fourth Quarter 2012 Highlights

Fourth quarter 2012 results, as compared to third quarter 2012 results
where applicable, were as follows:

• 
  As previously reported, production in the fourth quarter of 2012 was
  1.4 million barrels of oil equivalent (MMBOE), or 15,444 barrels of
  oil equivalent (BOE) per day (BOEPD), compared to 1.4 MMBOE, or
  15,245 ?BOEPD, pro forma to exclude production from assets sold
  
• 
  Product revenues from the sale of crude oil, natural gas liquids
  (NGLs) and natural gas were $76.0 million, or $53.48 ?per BOE,
  increases of one percent and six percent compared to $75.6 ?million, or
  $50.25 ?per BOE
  
• 
  Oil and NGL revenues were $63.2 million, or 83 percent of product
  revenues, a decrease of one ?percent compared to $63.7 ?million, or 84
  percent of product revenues
  
• 
  Operating margin, a non-GAAP (generally accepted accounting
  principles) measure, was $39.29 per BOE, an increase of 15 percent
  compared to $34.11 per BOE
  
• 
  Operating loss was $6.0 ?million, compared to a loss of $6.5 million,
  excluding impairments and loss on firm transportation commitment
  
• 
  Adjusted EBITDAX, a non-GAAP measure, was $62.3 million, an increase
  of two percent compared to $61.2 ?million
  
• 
  Loss attributable to common shareholders (which includes our preferred
  stock dividend) was $56.1 ?million, or $1.05 per diluted share,
  compared to a loss of $32.6 ?million, or $0.71 per diluted share
  
• 
  Adjusted loss attributable to common shareholders (which includes our
  preferred stock dividend), a non-GAAP measure which excludes the
  effects of certain costs and other gains or losses that affect
  comparability to other periods, of $11.8 ?million, or $0.22 per diluted
  share, compared to a loss of $7.3 million, or $0.16 ?per diluted share
  

A recently completed Eagle Ford Shale (0.9 net) well, the Technik #1H in
Lavaca County with 18 frac stages, tested at an initial rate of 1,136
barrels of oil and 1,853 thousand cubic feet (Mcf) per day on a 25/64^th
inch choke, with flowing casing pressure of approximately 2,350 psi.

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

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, 'In
the fourth quarter, our operating cash flows remained strong and our
margins continued to improve as a result of increased oil production,
attractive oil prices and lower operating expenses. We expect oil
production to increase further in 2013 and comprise over 85 ?percent of
product revenues and over 60 percent of production.

'We also strengthened our balance sheet in 2012. At year-end 2012, we
had over $300 million of financial liquidity and a leverage ratio of
approximately 2.3 times Adjusted EBITDAX, so that we expect to be able
to fund our 2013 capital program from operating cash flows and
borrowings under our revolver. Moreover, we are considering the sale of
a portion of our working interest in our Lavaca County Eagle Ford Shale
acreage, which would further improve liquidity and reduce the outspend
of cash flows.?

Mr. Whitehead concluded, 'Our steadily improving results have been
driven primarily by our oily Eagle Ford Shale play where we
significantly increased our acreage and drilling inventory during 2012.
Building on this success, we plan to commit approximately 88 ?percent of
estimated 2013 capital expenditures to the Eagle Ford Shale, drilling
approximately 38 ?(28.8 ?net) wells and focusing on expanding our Eagle
Ford Shale position.?

Full-Year 2012 Financial Results

For the year ended December 31, 2012, we incurred an operating loss of
$147.1 million, which included impairment charges and loss on firm
transportation obligations of $121.8 million, compared to a loss in 2011
of $155.4 million, which included impairment charges of $104.7 ?million.
Adjusted loss attributable to common shareholders, excluding the effects
of changes in derivatives fair value, impairments, restructuring costs
and other gains or losses that affect comparability to the prior year
period, and including the preferred stock dividend of $1.7 million, was
$36.6 ?million, or $0.76 per diluted share, in 2012 compared to a loss of
$47.7 ?million, or $1.04 ?per diluted share, in 2011. Loss attributable to
common shareholders (which includes our preferred stock dividend) was
$106.3 ?million, or $2.22 per diluted share, in 2012 compared to a loss
of $132.9 million, or $2.90 ?per diluted share, in 2011. The decrease was
due primarily to the $8.3 ?million decrease in operating loss, a $22.3
million decrease in the loss on the extinguishment of debt and a
$20.5 ?million increase in derivatives income.

Fourth Quarter 2012 Results

Overview of Financial Results

The $81.1 million operating loss in the fourth quarter of 2012 was $56.6
million higher than the $24.5 ?million loss in the third quarter of 2012
due primarily to a $74.5 million increase in impairment expense
associated with our Marcellus Shale assets and a $5.1 ?million increase
in depreciation, depletion and amortization (DD&A) expenses. The effect
of these items was partially offset by a $4.1 million decrease in total
direct operating expenses, a $17.3 million decrease in loss on firm
transportation obligations and a $1.8 ?million decrease in exploration
expenses. Oil and NGL revenues were $63.2 ?million in the fourth quarter
of 2012, a slight decrease compared to $63.7 million in the third
quarter of 2012 due primarily to slightly lower prices. Oil and NGL
revenues were 83 ?percent of product revenues in the fourth quarter of
2012, compared to 84 percent in the third quarter of 2012.

Pricing

Our fourth quarter 2012 realized oil price was $99.30 per barrel,
compared to $99.45 per barrel in the third quarter of 2012. Our fourth
quarter 2012 realized NGL price was $32.40 per barrel, compared to
$32.94 per barrel in the third quarter of 2012. Our fourth quarter 2012
realized natural gas price was $3.41 per Mcf, compared to $2.72 per Mcf
in the third quarter of 2012. Adjusting for oil and gas hedges, our
fourth quarter 2012 effective oil price was $106.33 per barrel and our
effective natural gas price was $3.83 per Mcf, or increases of $7.03 per
barrel and $0.42 per Mcf over the realized prices.

Production

Production in the fourth quarter of 2012 and full-year 2012 exceeded the
upper end of our guidance. On a pro forma basis to exclude production
from assets sold in 2011 and 2012, production in the fourth quarter of
2012 was 1.4 ?MMBOE, or 15,444 BOEPD, compared to 1.4 MMBOE, or 15,245
BOEPD, in the third quarter of 2012. As a percentage of total equivalent
production, oil and NGL volumes were 56 ?percent in the fourth quarter of
2012, compared to 52 percent in the third quarter of 2012.

Operating Expenses

As discussed below, fourth quarter 2012 total direct operating expenses
decreased $4.1 million, or approximately 17 ?percent, to $20.2 ?million,
or $14.19 ?per BOE produced, compared to $24.3 million, or $16.14 per BOE
produced, in the third quarter of 2012.

• 
  Lease operating expenses increased by $0.4 million to $6.6 million, or
  $4.68 ?per BOE produced, from $6.2 ?million, or $4.13 per BOE produced,
  in the third quarter due primarily to higher subsurface workover
  expenses in East Texas.
  
• 
  Gathering, processing and transportation expenses decreased by $0.6
  million to $2.5 ?million, or $1.78 per BOE produced, from $3.1 million,
  or $2.08 per BOE produced, in the third quarter due primarily to the
  divestiture of Appalachian assets in July 2012.
  
• 
  Production and ad valorem taxes decreased by 41 percent to
  $2.7 ?million, or 3.6 percent of product revenues, from $4.6 ?million,
  or 6.1 percent of product revenues, in the third quarter due primarily
  to the divestiture of Appalachian assets in July 2012.
  
• 
  General and administrative (G&A) expenses, excluding share-based
  compensation, decreased by $2.1 ?million, or 20 ?percent, to
  $8.3 ?million, or $5.82 per BOE produced, from $10.4 million, or $6.88
  per BOE produced, in the third quarter due primarily to a $1.4 ?million
  decrease in restructuring costs as a result of higher costs in the
  third quarter related to the sale of our Appalachian assets and the
  closing of our Pittsburgh office.
  

Exploration expenses decreased by $1.9 million, or 20 percent, to
approximately $7.4 ?million in the fourth quarter of 2012 from
approximately $9.3 ?million in the third quarter due primarily to the
divestiture of Appalachian assets in July 2012.

DD&A expenses increased by $5.1 million, or 10 percent, to
$54.4 ?million, or $38.32 per BOE produced, in the fourth quarter of 2012
from $49.3 million, or $32.80 per BOE produced, in the third quarter due
primarily to the continued transition towards higher cost oil versus gas
wells, as well as the impact of negative natural gas reserve revisions.

Impairment expense increased to $75.2 ?million in the fourth quarter of
2012 from $0.7 million in the third quarter due to the write-down of our
Marcellus Shale assets, primarily as a result of lower year-end gas
prices and the resultant reduction in proved reserves.

Capital Expenditures

During the fourth quarter of 2012, oil and gas capital expenditures were
approximately $118 million, compared to $85 ?million in the third
quarter, consisting of:

• 
  $100 million for drilling and completion activities
  
• 
  $5 million for seismic, pipeline, gathering and facilities
  
• 
  $13 million for leasehold acquisitions, field projects and other
  

Capital expenditures during 2012 were approximately $384 million,
approximately $34 million higher than the upper end of previous
guidance. The increase was attributable to:

• 
  an additional 38 percent working interest in six Lavaca County Eagle
  Ford Shale wells
  
• 
  increased costs on recent Eagle Ford Shale wells due to operational
  issues
  
• 
  an acceleration into 2012 of certain 2013 drilling and completion
  expenditures, along with related pipeline expansion costs
  
• 
  additional Eagle Ford Shale lease acquisition costs
  
• 
  a vertical core test of the Pearsall Shale
  

As previously disclosed, we added approximately 18.3 MMBOE of proved
reserves during 2012, prior to negative revisions of 28.7 MMBOE due
primarily to benchmark natural gas prices in 2012 which were 33 percent
lower than in 2011. Reserve replacement cost per BOE, defined as capital
expenditures divided by reserve additions, excluding revisions, was
approximately $21 per BOE. During 2012, we replaced approximately 280
percent of production, excluding revisions.

2013 Guidance

2013 guidance assumes that our working interest in a majority of our
2013 Lavaca County Eagle Ford Shale wells averages approximately 94
percent. 2013 guidance highlights are as follows:

• 
  Production is expected to be approximately 5.7 to 6.2 MMBOE (34.0 to
  37.0 billion cubic feet of natural gas equivalent), or approximately
  15,500 to 16,900 BOEPD, compared to 2012 ?production of approximately
  5.8 ?MMBOE, or 15,776 BOEPD, pro forma to exclude 0.7 MMBOE of
  production in 2012 from divested Appalachian assets.
  
  
  • 
    Crude oil production is expected to increase by 23 to 37 percent
    over 2012 levels (a 12 to 24 percent increase in crude oil and
    NGLs combined). Crude oil and NGLs are expected to comprise
    approximately 60 to 65 ?percent of total production, compared to 48
    percent during 2012.
    
  • 
    Production during January 2013 was approximately 15,600 BOEPD,
    approximately 42 ?percent of which was crude oil and approximately
    16 percent of which was NGLs.
    
• 
  Product revenues are expected to be approximately $330 to $364
  million, compared to 2012 ?product revenues of $310 ?million, excluding
  the impact of any hedges.
  
  
  • 
    Crude oil and NGL product revenues are expected to be
    approximately 87 percent of total product revenues, compared to 84
    percent during 2012.
    
  • 
    Approximately 58 percent of the midpoint of estimated crude oil
    production and 55 percent of the midpoint of estimated natural gas
    production are currently hedged.
    
  • 
    Settlements of current commodity hedges are expected to result in
    cash receipts of approximately $13 ?million.
    
• 
  Adjusted EBITDAX, a non-GAAP measure, is expected to be approximately
  $235 to $280 million, compared to 2012 Adjusted EBITDAX of $248
  million.
  
• 
  Capital expenditures are expected to be $360 to $400 ?million, compared
  to approximately $385 ?million of 2012 capital expenditures.
  
  
  • 
    Approximately 88 percent of capital expenditures are expected to
    be allocated to the Eagle Ford Shale and approximately 91 percent
    to development activities.
    
  • 
    2013 capital expenditures include $310 to $345 million for
    drilling and completions, $28 to $30 million for lease
    acquisitions and $22 to $25 million for pipeline, gathering,
    seismic and facilities.
    

Please see the Guidance Table included in this release for guidance
estimates for 2013. 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, 2012, we had total debt with a carrying value of $595
million ($600 million aggregate principal amount), consisting of $295
million of 10.375 percent senior unsecured notes due 2016 and $300
million principal amount of 7.25 ?percent senior unsecured notes due 2019.

As of December 31, 2012, we had no borrowings under our revolving credit
facility (the 'Revolver?), with approximately $298 million of unused
borrowing capacity under the Revolver commitment. Together with cash and
cash equivalents of approximately $18 million, our financial liquidity
was approximately $316 million. Our indebtedness at December 31, 2012,
net of cash and cash equivalents, was approximately $577 ?million,
representing 39 ?percent of book capitalization and 2.3 times 2012
Adjusted EBITDAX of $247.6 ?million. We have no debt maturities until
2016. As of February 15, 2013, we had approximately $270 million of
available borrowing capacity under the Revolver and approximately
$4 ?million of cash and cash equivalents, for available financial
liquidity of approximately $274 million.

In October 2012, we completed concurrent public offerings of 9,200,000
shares of our common stock and 1,150,000 ?depositary shares, each
representing a 1/100^th interest in a share of our 6 percent
Series A convertible perpetual preferred stock. The two offerings
provided approximately $154 ?million of net proceeds after issuance costs.

Interest expense decreased to $14.5 ?million in the fourth quarter of
2012 from $15.0 ?million in the third quarter due to lower average levels
of debt outstanding.

During the fourth quarter of 2012, derivatives income was $4.9 ?million,
compared to a derivatives loss of $12.3 ?million in the third quarter.
Fourth quarter 2012 cash settlements of derivatives resulted in net cash
receipts of $5.5 ?million, compared to $9.2 million of net cash receipts
in the third quarter.

Derivatives Update

To support our operating cash flows, we hedge a portion of our oil and
natural gas production at pre-determined prices or price ranges. Based
on hedges currently in place, we have hedged approximately 4,600 ?barrels
of daily crude oil production in 2013, or approximately 58 percent of
the midpoint of 2013 crude oil production guidance, at a weighted
average floor/swap price of $97.35 per barrel. We have also hedged
approximately 20,000 Mcf of daily natural gas production in 2013, or
approximately 55 percent of the midpoint of 2013 natural gas production
guidance, at a weighted average floor/swap price of $3.76 per Mcf.

Please see the Derivatives Table included in this release for our
current derivative positions.

Explanation of Non-GAAP Operating Margin per BOE

Operating margin is a non-GAAP financial measure under SEC regulations
which represents total product revenues less total direct operating
expenses. Operating margin per BOE is equal to operating margin divided
by total equivalent crude oil, NGL and natural gas production. Operating
margin is not adjusted for the impact of hedges. We believe that
operating margin per BOE 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.

Fourth Quarter and Full-Year 2012 Financial and Operational Results
Conference Call

A conference call and webcast, during which management will discuss
fourth quarter and full-year 2012 financial and operational results, is
scheduled for Thursday, February 21, 2013 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 toll free 1-866-630-9986 five to 10
minutes before the scheduled start of the conference call (use the
passcode 7342669), 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 1-888-203-1112
(international: 719-457-0820) and using the replay code 7342669. 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 oil and natural gas in various domestic onshore regions including
Texas, Oklahoma, Mississippi and Pennsylvania.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, natural gas liquids 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, natural
gas liquids 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 $(0.1) million and $0.7 million attributable to
these awards is included in the three and twelve months ended December
31, 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) Loss, as adjusted, attributable to common shareholders represents
loss attributable to common shareholders adjusted to exclude the
effects, net of income taxes, of non-cash changes in the fair value of
derivatives, impairments, restructuring costs, gain on the sale of
assets and loss on firm transportation commitment. 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. Loss, as adjusted, attributable to common
shareholders is not a measure of financial performance under GAAP and
should not be considered as a measure of liquidity or as an alternative
to loss attributable to common shareholders.

(b) Adjusted EBITDAX represents net loss before income tax benefit,
interest expense, depreciation, depletion and amortization expenses,
exploration expenses and share-based compensation expense, further
adjusted to exclude the effects of non-cash changes in the fair value of
derivatives, loss on firm transportation commitment, impairments, gain
on the sale of assets, loss on the extinguishment of debt and other
non-cash items. 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.

(a) Assumes average benchmark prices of $90.00 per barrel for crude oil
and $3.50 per MMBtu for natural gas,prior to any premium or discount for
quality, basin differentials, the impact of hedges and other
adjustments. NGL realized pricing is assumed to be $29.76 per barrel.

(b) Adjusted EBITDAX is not a measure of financial performance under
GAAP and should not be considered as a measure of liquidity or as an
alternative to net income.

(c) Seismic expenditures are also reported as a component of exploration
expense and as a component of net cash provided by operating activities.

(a) This written swaption contract gives our counterparties the option
to enter into a fixed price swap with us at a future date. If the
forward commodity price for calendar year 2014 is higher than or equal
to $100.00 per barrel on December 31, 2013, the counterparty will
exercise its option to enter into a fixed price swap at $100.00 per
barrel for calendar year 2014, at which point the contract functions as
a fixed price swap. If the forward commodity price for calendar year
2014 is lower than $100.00 per barrel on December 31, 2013, the option
expires and no fixed price swap is in effect.

(b) The option exercise date on these swaptions for calendar year 2014
is June 28, 2013.

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 2013 would increase or decrease by approximately
$9.8 million. In addition, we estimate that for every $10.00 per barrel
increase or decrease in the crude oil price, operating income for 2013
would increase or decrease by approximately $22.6 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