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 2013 RESULTS AND

UPDATES 2013 GUIDANCE, INCLUDING RECENT EAGLE FORD SHALE ACQUISITION

2013 OIL PRODUCTION GROWTH NOW EXPECTED TO BE 60 TO 78 PERCENT

RECENT RESULTS HAVE DE-RISKED LAVACA COUNTY EAGLE FORD SHALE POTENTIAL

INITIAL SUCCESS IDENTIFIES ADDITIONAL EAGLE FORD SHALE INTERVAL

RADNOR, PA (Globe Newswire) May 8, 2013 – Penn Virginia Corporation (NYSE: PVA) today reported financial results for the three months ended March 31, 2013 and provided an update of its operations and 2013 guidance.

First Quarter 2013 Highlights

First quarter 2013 financial results, as compared to fourth quarter 2012 results, were as follows:

Recent operational highlights were as follows:

Definitions of non-GAAP financial measures and reconciliations of these non-GAAP financial measures to GAAP-based measures appear later in this release. First quarter financial and production results do not reflect any contributions from the acquired MHR assets.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “In the first quarter, our operating cash flows and margins remained strong as a result of the continued growth in oil production and higher oil price realizations. We expect oil production to increase by nearly 70 percent in 2013 over 2012, comprising over 86 percent of product revenues and over 65 percent of production.

“In April, we closed the MHR Eagle Ford Shale acquisition and also completed a highly successful $775 million debt offering of 8.5 percent senior notes due 2020 to help finance this acquisition, as well as to repurchase our 10.375 percent senior notes due 2016. The MHR acquisition has significantly expanded our Eagle Ford Shale drilling inventory in a core area of the play and has positioned us for substantial growth over the next few years. Following these transactions, our balance sheet remains sound with approximately $280 million of pro forma financial liquidity and a pro forma leverage ratio of approximately 3.2 times Adjusted EBITDAX. Furthermore, we have increased the level of our crude oil hedges in 2013 and 2014 in conjunction with the MHR acquisition. We expect to fund our 2013 capital program from operating cash flows and borrowings under our revolver. We are also considering asset sales during 2013 and 2014 to further improve liquidity.”

First Quarter 2013 Results

Overview of Financial Results

The $3.0 million operating loss in the first quarter of 2013 was $78.1 million lower than the $81.1 million loss in the fourth quarter of 2012, due primarily to a $75.2 million decrease in impairment expense (none in the current quarter), a $6.2 million increase in total product revenues, a $2.8 million decrease in depreciation, depletion and amortization (DD&A) expense, a $1.1 million decrease in exploration expense and a $1.0 million decrease in share-based compensation expense. The effect of these items was partially offset by a $7.0 million increase in total direct operating expenses and a $1.2 million decrease in other revenues.

Product Revenues

Total product revenues were $82.2 million in the first quarter of 2013, an eight percent increase compared to $76.0 million in the fourth quarter of 2012, due primarily to an eight percent increase in average product pricing from $53.48 per BOE to $57.61 per BOE. Oil and NGL revenues were $70.2 million in the first quarter of 2013, an 11 percent increase compared to $63.2 million in the fourth quarter of 2012, due primarily to a six percent increase in average oil and NGL prices and a four percent increase in oil and NGLs production. Oil and NGL revenues were 85 percent of product revenues in the first quarter of 2013, compared to 83 percent in the fourth quarter of 2012.

Operating Expenses

As discussed below, first quarter 2013 total direct operating expenses increased $7.0 million to $27.2 million, or $19.06 per BOE produced, compared to $20.2 million, or $14.19 per BOE produced, in the fourth quarter of 2012.

Exploration expense decreased by $1.1 million to $6.3 million in the first quarter of 2013 from $7.4 million in the fourth quarter of 2012. The decrease was due primarily to a reduction in our unproved property asset base.

DD&A expense decreased by $2.8 million to $51.6 million, or $36.14 per BOE produced, in the first quarter of 2013 from $54.4 million, or $38.32 per BOE produced, in the fourth quarter of 2012, due primarily to a decrease in higher cost natural gas production as well as year-end 2012 adjustments.

First Quarter 2013 Operational Results

Pricing

Our first quarter 2013 realized oil price was $105.28 per barrel, compared to $99.30 per barrel in the fourth quarter of 2012. Our first quarter 2013 realized NGL price was $30.45 per barrel, compared to $32.40 per barrel in the fourth quarter of 2012. Our first quarter 2013 realized natural gas price was $3.38 per thousand cubic feet (Mcf), compared to $3.41 per Mcf in the fourth quarter of 2012. Adjusting for oil and gas hedges, our first quarter 2013 effective oil price was $109.97 per barrel and our effective natural gas price was $3.59 per Mcf, or increases of $4.69 per barrel and $0.21 per Mcf over the realized prices.

Production

Production in the first quarter of 2013 was 1.4 MMBOE, or 15,857 BOEPD, compared to 1.4 MMBOE, or 15,444 BOEPD, in the fourth quarter of 2012. As a percentage of total equivalent production, oil and NGL volumes were 58 percent in the first quarter of 2013, compared to 56 percent in the fourth quarter of 2012. The table below gives quarterly production detail.

Notes – Numbers may not add due to rounding. First quarter of 2012 had 91 days.

Capital Expenditures

During the first quarter of 2013, oil and gas capital expenditures were approximately $96 million, a decrease of 19 percent compared to $118 million in the fourth quarter of 2012, consisting of:

Operational Update

Eagle Ford Shale

Net production from the Eagle Ford Shale was 7,523 BOEPD in the first quarter of 2013, compared to 6,872 BOEPD in the fourth quarter of 2012, or an increase of over nine percent. During the first quarter of 2013, we completed eight (6.8 net) operated wells and three (1.5 net) non-operated wells. Currently, we have a total of 120 (84.2 net) Eagle Ford Shale producing wells, with 15 (8.8 net) wells either completing or waiting on completion and seven (4.1 net) wells being drilled. Our completion activity has accelerated in the second quarter of 2013.

Following the MHR acquisition, we estimate that we have approximately 645 (420 net) drilling locations, which is an eight-year drilling inventory with an ongoing six-rig program. We are currently running five operated rigs and two non-operated rigs, but will drop one operated rig by mid-year 2013 pursuant to our stated capital program.

Set forth below are the results and statistics for recent Eagle Ford Shale wells drilled and completed.

A focus going forward will be to reduce our completion costs by $1.0 to $1.5 million per well. We expect these savings will occur primarily in the second half of the year. In addition, we expect to further reduce well costs by approximately $0.2 to $0.5 million per well by increasing the use of pad drilling in conjunction with a downspaced development program. With respect to pad drilling, five wells (Rhino Hunter #1H, Zebra Hunter #1H and Elk Hunter #1H, #2H and #3H) were recently drilled off of two pads with effective spacing of approximately 70 acres and the results have been excellent as shown in the table above. Three additional wells were also completed in the second quarter at a spacing of approximately 70 acres and flowback recently began. With continued leasing in both Gonzales and Lavaca Counties and as our Lavaca County acreage has been de-risked and further developed, we anticipate additional downspaced wells will be added to our 645-well drilling inventory.

Our recent results in Lavaca County have exceeded our expectations. We have had drilling success in the eastern and southernmost portions of our acreage in the lower Eagle Ford Shale and recently we have had encouraging results on a

well drilled laterally in an upper portion of the Eagle Ford Shale. We expect to drill an additional well in this upper portion of the Eagle Ford Shale in a different location to help define its extensiveness across our acreage.

Our first horizontal exploratory well in the Pearsall Shale, located in Gonzales County, was recently drilled, completed and turned in line with an initial rate of 992 Mcf per day and 140 BOPD. While the initial rate is lower and gassier than we had hoped, we still consider this a positive data point which may result in an additional Pearsall Shale tests further downdip where, similar to the Eagle Ford Shale, there may be higher reservoir pressures and therefore higher production rates for oil and gas.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of March 31, 2013, we had total debt with a carrying value of $633.1 million ($638.0 million aggregate principal amount), consisting of $295.1 million of 10.375 percent senior unsecured notes due 2016, $300.0 million principal amount of 7.25 percent senior unsecured notes due 2019 and $38.0 million outstanding under our revolving credit facility (Revolver), with $259.2 million of unused borrowing capacity under the Revolver. Together with cash and cash equivalents of $14.4 million, our financial liquidity was $273.6 million. Our indebtedness at March 31, 2013, net of cash and cash equivalents, was $618.7 million, representing 41 percent of book capitalization and 2.5 times trailing twelve months’ Adjusted EBITDAX of $243.7 million.

In April 2013, we completed the MHR acquisition, in connection with which we paid a purchase price of approximately $400 million, consisting of approximately $360 million in cash and the issuance of 10.0 million shares of common stock to MHR. We also paid closing adjustments of approximately $19 million and assumed approximately $16 million of net current liabilities to account for an effective date of January 1, 2013. To finance the MHR acquisition, as well as the repurchase of our 10.375 percent senior unsecured notes, we issued $775 million of 8.5 percent unsecured senior notes due 2020.

Pro forma as of and for the twelve months ended March 31, 2013 to adjust for these transactions, we had $1,075 million of total debt, approximately $5 million of cash and cash equivalents, approximately $316 million of trailing twelve months’ Adjusted EBITDAX and approximately $275 million of availability under the Revolver. As a result, our pro forma financial liquidity was approximately $280 million and our pro forma indebtedness, net of cash and cash equivalents, was approximately $1,070 million, representing 53 percent of book capitalization and 3.4 times trailing twelve months’ Adjusted EBITDAX. In May 2013, the borrowing base under our Revolver will be redetermined. Because the redetermination will consider the acquired MHR assets and Eagle Ford Shale drilling activity through March 31, 2013, we expect our borrowing base to be substantially higher than the current borrowing base of approximately $276 million.

During the first quarter of 2013, interest expense was flat at $14.5 million compared to the fourth quarter of 2012.

During the first quarter of 2013, derivatives loss was $7.8 million, compared to a derivatives income of $4.9 million in the fourth quarter of 2012. First quarter 2013 cash settlements of derivatives resulted in net cash receipts of $3.6 million, compared to $5.5 million of net cash receipts in the fourth quarter of 2012.

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 7,600 barrels of daily crude oil production over the final three quarters of 2013, or approximately 65 percent of the midpoint of the final three quarters’ 2013 crude oil production guidance, at a weighted average floor/swap price of $94.91 per barrel. We have also hedged approximately 25,000 MMBtu of daily natural gas production over the final three quarters of 2013, or approximately 70 percent of the midpoint of 2013 of the final three quarters’ natural gas production guidance, at a weighted average floor/swap price of $3.77 per Mcf.

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

2013 Guidance

Previous guidance refers to guidance provided in connection with the April 3, 2013 announcement of the MHR acquisition. Updated 2013 guidance highlights are as follows:

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.

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.

First Quarter 2013 Conference Call

A conference call and webcast, during which management will discuss first quarter 2013 financial and operational results, is scheduled for Thursday, May 9, 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 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes before the scheduled start of the conference call (use the conference code 33057398), 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 1-855-859-2056 (international: 1-404-537-3406) and using the replay code 33057398. 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 exploration, development and production of oil, NGLs and natural gas in various domestic onshore regions of the United States, with a primary focus in Texas, and to a lesser extent, the Mid-Continent, Mississippi and the Marcellus Shale in Appalachia. 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: our ability to successfully integrate the assets acquired in the MHR acquisition with ours and realize the anticipated benefits from the acquisition; the volatility of commodity prices for oil, NGLs and natural gas; our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production; our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations; any impairments, write-downs or write-offs of our reserves or assets; the projected demand for and supply of oil, NGLs and natural gas; reductions in the borrowing base under our revolving credit facility; our ability to contract for drilling rigs, supplies and services at reasonable costs; our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices; the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural 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.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - 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 2013. 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.