Exhibit 99.1

Four Radnor Corporate Center, Suite 200

Radnor, PA 19087

Ph: (610) 687-8900 Fax: (610) 687-3688

www.pennvirginia.com

FOR IMMEDIATE RELEASE

PENN VIRGINIA CORPORATION ANNOUNCES FIRST QUARTER 2011 RESULTS

INITIAL PRODUCTION AND EXPANDED POSITION IN THE EAGLE FORD SHALE

RADNOR, PA (BusinessWire) May 4, 2011 – Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended March 31, 2011 and provided an update of full-year 2011 guidance.

First Quarter 2011 Highlights

First quarter 2011 results, as compared to first quarter 2010 results, are as follows:

The operating loss and net loss from continuing operations in the first quarter of 2011 included increases relative to the first quarter of 2010 in exploratory dry hole costs of $16.4 million in the Mid-Continent region and unproved leasehold amortization expense of $5.5 million, due to leasehold acquisitions primarily in the Marcellus and Eagle Ford Shales during 2010.

Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the text and financial tables later in this release.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “In late 2010 we made the strategic decision to shift our production and reserve mix towards oil and natural gas liquids (NGLs) through a reduction in natural gas drilling and an increase in drilling and leasehold acquisitions in oil and liquids-rich play types. During the first quarter of 2011, we continued to make progress in implementing this strategy as we reported the first contributions from the oily Eagle Ford Shale, a play in which we now have three operated rigs, are currently

drilling our seventh well, have just recently completed our second and third wells and have expanded our position to approximately 13,000 net acres. Our initial well continues to outperform our original expectations, still producing almost 500 barrels of oil and 300 Mcf of wet gas per day after 80 days of production. The gas is currently being flared until gathering facilities are constructed, after which this gas will be processed. The gathering facilities are expected to be in place by early June 2011.

“For full-year 2011, we expect oil and NGLs to contribute between 28 and 30 percent of total equivalent production, as compared to approximately 18 percent of 2010 total equivalent production, and we expect to exit 2011 with approximately 35 percent of fourth quarter total equivalent production from oil and NGLs. Despite this transition from historical investments in natural gas plays to primarily oil plays, we have kept our full-year 2011 production guidance range of 50 to 54 Bcfe unchanged as we expect significant increases in Eagle Ford Shale production during the second half of the year.”

Mr. Whitehead continued, “In the Marcellus Shale, we recently completed our first two horizontal Marcellus Shale wells. We are continuing to seek alternatives for our position in this promising but gassy and capital-intensive play and may also monetize other non-core gas assets and use the proceeds to expand our Eagle Ford Shale and other oil and liquids-rich plays. We are pleased with the 2010 results from our liquids-rich horizontal Cotton Valley wells and, given the possibility of monetizing non-core gas assets during 2011, may use a portion of such proceeds to recommence drilling of horizontal Cotton Valley wells.

“First quarter 2011 exploration results in the Mid-Continent were disappointing as we have previously discussed and we expensed approximately $16.4 million during the first quarter related to three unsuccessful wells. Despite these exploratory setbacks, we were otherwise pleased with our first quarter results, especially the acceleration of our Eagle Ford drilling program.”

Mr. Whitehead concluded, “With our strong financial condition and liquidity, we are well-positioned to execute on our capital plans in 2011. During the final three quarters of 2011, approximately 56 percent of our expected natural gas production is hedged at a weighted average floor / swap price of $5.09 per MMBtu and approximately 22 percent of our expected crude oil production is hedged at weighted average floor and ceiling / swap prices of between approximately $94 and $106 per barrel. In April 2011, we completed a $300 million offering of 7.25 percent senior unsecured notes due 2019, providing us with low-cost, long-term capital.”

First Quarter 2011 Financial and Operational Results

The operating loss of $28.5 million was $28.6 million lower than the operating income of $0.1 million in the prior year quarter, due primarily to a $23.5 million increase in exploratory expense and a $4.8 million increase in DD&A expense. The $7.1 million decrease in natural gas and other revenues and $1.0 million increase in other operating expenses were largely offset by a $7.8 million increase in oil and NGL revenues.

As shown in the table below, production in the first quarter of 2011 was approximately 12.2 Bcfe, or 135.2 MMcfe per day, a 21 percent increase as compared to 10.0 Bcfe, or 111.6 MMcfe per day, pro forma to exclude 0.3 Bcfe of production from Gulf Coast assets sold in January 2010 (reported production was 10.3 Bcfe, or 114.9 MMcfe per day), and a five percent decrease from 13.1 Bcfe, or 142.5 MMcfe per day, in the fourth quarter of 2010. As a percentage of total equivalent production, oil and NGL volumes were 20 percent in the first quarter of 2011, as compared to 17 percent in the prior year period.

The year-over-year production increase was due to the effects of significantly increased drilling activity during 2010, while the sequential quarterly decrease was due to a reduction in natural gas drilling and base production declines, as well as a lag in initial production volumes from the Eagle Ford Shale due to completion delays associated with the drilling of multiple wells from the same location. Please see our separate operational update news release dated May 4, 2011 for a more detailed discussion of operations.

Note - Numbers may not add due to rounding.

Our realized first quarter 2011 natural gas price was $4.23 per thousand cubic feet (Mcf), 24 percent lower than the $5.60 per Mcf price in the first quarter of 2010 and 19 percent higher than the $3.57 per Mcf price in the fourth quarter of 2010. Our first quarter 2011 realized oil price was $88.37 per barrel, 19 percent higher than the $74.44 per barrel price in the first quarter of 2010 and seven percent higher than the $82.84 per barrel price in the fourth quarter of 2010. Our first quarter 2011 realized NGL price was $45.11 per barrel, one percent higher than the $44.64 per barrel price in the first quarter of 2010 and seven percent higher than the $42.15 per barrel price in the fourth quarter of 2010. Adjusting for oil and gas hedges, the first quarter 2011 effective natural gas price was $4.95 per Mcf and our effective oil price was $87.17 per barrel, or an increase of $0.72 per Mcf and decrease of $1.20 per barrel, respectively, over the realized prices.

As discussed below and due primarily to the 18 percent increase in reported oil and gas production volumes, first quarter 2011 direct operating expenses increased $2.7 million, or approximately 10 percent, to $30.9 million, or $2.54 per Mcfe produced, as compared to $28.2 million, or $2.73 per Mcfe produced, in the first quarter of 2010.

Exploration expense increased $23.5 million to $29.5 million in the first quarter of 2011 from $6.0 million in the prior year quarter, due primarily to a $16.4 million increase in dry hole costs attributable to exploratory drilling in the Mid-Continent region, a $5.5 million increase in unproved property amortization resulting from recent acquisitions of unproved leasehold and a $1.4 million increase in geological and geophysical costs.

DD&A expense increased by $4.8 million, or 16 percent, to $34.8 million, or $2.86 per Mcfe produced, in the first quarter of 2011 from $30.0 million, or $2.90 per Mcfe produced, in the prior year quarter due primarily to higher production volumes.

Full-Year 2011 Guidance Update

Full-year 2011 guidance highlights are as follows:

As previously announced, we shifted an additional operated drilling rig from the Mid-Continent to the Eagle Ford Shale, resulting in three operated rigs currently drilling in the Eagle Ford Shale. Furthermore, we have increased our acreage position in the Eagle Ford Shale to 12,700 net acres from our original position of 6,800 net acres in August 2010. We expect production in the second quarter of 2011 to be consistent with that of the first quarter, after which we expect production in the second half of the year to be significantly higher due to the expected impact of three rigs drilling in the Eagle Ford Shale from the second quarter forward.

Please see the Guidance Table included in this release for guidance estimates for full-year 2011. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of March 31, 2011, we had outstanding borrowings of $509 million (carrying value; $530 million aggregate principal amount), consisting of $293 million (carrying value; $300 million aggregate principal amount) of senior unsecured notes due 2016 and $216 million (carrying value; $230 million aggregate principal amount) of convertible senior subordinated notes due 2012, with no borrowings under our revolving credit facility. Net of cash and equivalents of approximately $48 million, our indebtedness at March 31, 2011 was approximately $460 million, or 33 percent of book capitalization. We currently have no borrowings under our revolving credit facility.

In April 2011, we completed the offering of $300 million of 7.25 percent senior unsecured notes due 2019. Approximately $241 million of the net proceeds of $293 million were used to fund a tender offer for approximately 98 percent of our convertible senior subordinated notes. We expect to use the remaining net proceeds of approximately $52 million to fund a portion of our capital expenditures program.

Interest expense decreased slightly to $13.5 million in the first quarter of 2011 from $13.7 million in the first quarter of 2010 due primarily to an increase in capitalized interest.

Due to fluctuations in commodity prices during the first quarter of 2011, derivatives income was $1.3 million as compared to derivatives income of $29.9 million in the prior year quarter. First quarter 2011 cash settlements of derivatives resulted in net cash receipts of $6.7 million, as compared to $8.4 million of net cash receipts in the prior year quarter.

First Quarter 2011 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss first quarter 2011 financial and operational results, is scheduled for Thursday, May 5, 2011 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-630-9986 five to ten minutes before the scheduled start of the conference call (use the passcode 7415900), 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 7415900. 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.

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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; 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 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 costs and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves; drilling and operating risks; our ability to compete effectively against other independent and major oil and natural gas companies; uncertainties related to expected benefits from acquisitions of oil and natural gas properties; environmental liabilities that are not covered by an effective indemnity or insurance; the timing of receipt of necessary regulatory permits; the effect of commodity and financial derivative arrangements; our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms; the occurrence of unusual weather or operating conditions, including force majeure events; our ability to retain or attract senior management and key technical employees; counterparty risk related to their ability to meet their future obligations; changes in governmental 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.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME - unaudited

(in thousands, except per share data)

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

PENN VIRGINIA CORPORATION

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited

(dollars in millions except where noted)

We are providing the following guidance regarding financial and operational expectations for full-year 2011. These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes

PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited - (continued)

Note to Guidance Table:

The following table shows our current derivative positions.

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the last three quarters of 2011 would increase or decrease by approximately $28 million. In addition, we estimate that for every $10.00 per barrel increase or decrease in the crude oil price, operating income for the last three quarters of 2011 would increase or decrease by approximately $15 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.