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 2014 RESULTS

FIRST QUARTER ADJUSTED EBITDAX OF $94 MILLION ON RECORD OIL PRODUCTION

STRONG RESULTS FROM SECOND UPPER EAGLE FORD TEST WELL

EAGLE FORD NET ACREAGE INCREASED TO APPROXIMATELY 86,000 ACRES

DRILLING INVENTORY INCREASED SIGNIFICANTLY TO APPROXIMATELY 1,510 LOCATIONS

RADNOR, PA (Globe Newswire) May 12, 2014 – Penn Virginia Corporation (NYSE: PVA) today reported financial results for the three months ended March 31, 2014 and provided updates of its operations and 2014 guidance.

First Quarter 2014 Results and Highlights

First quarter 2014 financial results, with applicable comparisons to fourth quarter 2013 results, and highlights were as follows:

Recent operational results, with applicable comparisons to fourth quarter 2013 results, and 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.

Management Comment

“We are pleased with our financial results in the first quarter as our cash flow and margins remained strong,” said H. Baird Whitehead, President and Chief Executive Officer. “Despite a sizeable number of well completions coming online later than expected, we achieved a new quarterly oil production record. Due to continued success in adding to our Eagle Ford Shale acreage position, we are increasing our leasing capital expenditures guidance for the year, but otherwise our previously reported guidance remains unchanged. We continue our aggressive Eagle Ford Shale leasing effort, at attractive acquisition costs, as we draw closer to our stated minimum goal of 100,000 net acres.

“Initial testing of our adjacent Upper / Lower Eagle Ford Shale wells commenced in the first quarter and the initial results are strong. We saw initial production in excess of 2,000 BOEPD with a very high flowing pressure. Longer term testing will be necessary in order to fully understand the upside associated with the Upper Eagle Ford Shale, but we are very optimistic about the play.”

First Quarter 2014 Results

Overview of Results

Operating income of $14.9 million in the first quarter of 2014, excluding $57.4 million of gain on the sale of assets, was $0.6 million lower than $15.5 million in the fourth quarter of 2013, excluding $0.2 million of gain on the sale of assets. This slight decrease was due primarily to a $5.7 million increase in exploration expense, a $4.9 million increase in depreciation, depletion and amortization (DD&A) expense, a $4.4 million increase in production and ad valorem taxes and a $3.2 million increase in share-based compensation expenses. The effect of these increased expenses was largely offset by a $16.1 million increase in product revenues, a $1.0 million decrease in recurring general and administrative (G&A) expense and a $0.4 million decrease in lease operating, gathering, processing and transportation expenses.

Product Revenues

Total product revenues were $133.2 million in the first quarter of 2014, a 14 percent increase compared to $117.1 million in the fourth quarter of 2013, due primarily to a 10 percent increase in average product pricing to $70.01 per BOE from $63.58 per BOE, as well as a three percent increase in equivalent production. The realized oil price was four percent higher than in the fourth quarter. Oil and NGL revenues were $114.9 million in the first quarter, a nine percent increase compared to $105.0 million in the fourth quarter, due to a five percent increase in combined oil and NGL prices, as well as a four percent increase in combined oil and NGL production. Oil and NGL revenues were 86 percent of product revenues in the first quarter, compared to 90 percent in the fourth quarter. Natural gas revenues were $18.2 million in the first quarter, a 51 percent increase compared to $12.0 million in the fourth quarter, due to a 47 percent increase in natural gas prices, as well as a three percent increase in natural gas production.

Production

Note - Numbers may not add due to rounding. MBOE equals one thousand barrels of oil equivalent.

As shown in the table above, production in the first quarter of 2014 was 21,133 BOEPD, compared to 20,020 BOEPD in the fourth quarter of 2013. As a percentage of total equivalent production, oil and NGL volumes were 69 percent in the first quarter of 2014, compared to 68 percent in the fourth quarter of 2013.

Pricing

Our first quarter 2014 realized oil price was $98.12 per barrel, compared to $94.66 per barrel in the fourth quarter of 2013. Our first quarter 2014 realized NGL price was $41.27 per barrel, compared to $34.56 per barrel in the fourth quarter. Our first quarter 2014 realized natural gas price was $5.07 per thousand cubic feet (Mcf), compared to $3.45 per Mcf in the fourth quarter. Adjusting for oil and gas hedges, our first quarter 2014 effective oil price was $96.00 per barrel and our first quarter 2014 effective natural gas price was $4.85 per Mcf, or a decrease of $2.12 per barrel from the realized oil price and a decrease of $0.22 per Mcf in the realized gas price.

Operating Expenses

As discussed below, first quarter 2014 total direct operating expenses, excluding share-based compensation expenses, increased by $2.8 million to $30.6 million, or $16.08 per BOE produced, compared to $27.8 million, or $15.09 per BOE, in the fourth quarter of 2013.

Exploration expense increased to $8.6 million in the first quarter of 2014 from $2.9 million in the fourth quarter of 2013, primarily due to the acquisition of additional seismic in our Eagle Ford Shale area of interest.

DD&A expense increased by $5.0 million to $72.2 million, or $37.95 per BOE, in the first quarter of 2014, from $67.2 million, or $36.51 per BOE, in the fourth quarter of 2013, due primarily to higher overall production and a greater concentration of oil production from higher development-cost oil wells.

Capital Expenditures

During the first quarter of 2014, capital expenditures were approximately $182 million, an increase of $32 million, or 21 percent, compared to $150 million in the fourth quarter of 2013, consisting of:

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of March 31, 2014, we had total debt of $1,265 million, consisting of $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $775 million principal amount of 8.50 percent senior unsecured notes due 2020 and $190 million outstanding under our revolving credit facility (Revolver). Our leverage ratio under the Revolver was 3.6 times trailing twelve months’ pro forma Adjusted EBITDAX of approximately $353 million, compared to 3.7 times at December 31, 2013. In May 2014, the borrowing base under the Revolver was increased from $425 million to $475 million.

During the first quarter, interest expense was $22.5 million, of which $21.5 million was cash interest expense, compared to $22.3 million in the fourth quarter.

During the first quarter, derivatives loss was $15.7 million, compared to derivatives income of $2.4 million in the fourth quarter. First quarter 2014 cash settlements of derivatives resulted in net cash outlays of $3.1 million, compared to $2.7 million of net cash outlays in the fourth 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 11,700 barrels of daily crude oil production, or approximately 67 percent of the midpoint of guidance for the final three quarters of 2014, at a weighted average floor/swap price of $92.94 per barrel. For 2015, we have hedged approximately 10,000 barrels of daily crude oil production at a weighted average floor/swap price of $89.41 per barrel.

We have also hedged approximately 11,700 MMBtu of daily natural gas production, or approximately 29 percent of the midpoint of guidance for the final three quarters of 2014, at a weighted average floor/swap price of $4.16 per MMBtu. For the first quarter of 2015, we have hedged 5,000 MMBtu of daily natural gas production at a weighted average floor/swap price of $4.50 per MMBtu.

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

Eagle Ford Shale Operational Update

First Quarter 2014 Update

First quarter production of our Eagle Ford Shale operations was 15,152 BOEPD, up 15 percent compared to 13,145 BOEPD in the fourth quarter. First quarter oil production of our Eagle Ford Shale operations was 11,878 BOPD, 10 percent higher than 10,759 BOPD in the fourth quarter of 2013.

During the first quarter, we completed 16 (12.9 net) operated wells and participated in the completion of two (0.9 net) outside operated wells. As of March 31, 2014, we had 19 (11.1 net) wells completing or waiting on completion and six (3.4 net) wells being drilled.

Upper Eagle Ford (Marl) Shale Update

The Welhausen #A2H and Welhausen #B1H located in Lavaca County were completed and turned in line during March 2014. The two laterals are effectively 660 feet apart. The Welhausen #B1H landed in the Lower Eagle Ford Shale, which is where the vast majority of our wells traditionally have been completed. The Welhausen #B1H has a 5,584 foot lateral and 26 frac stages and flowed back at a pressure of 5,700 pounds per square inch (psi), with an initial potential (IP) of 1,536 BOEPD. The Welhausen #A2H was completed in the Upper Eagle Ford (Marl) Shale. The Welhausen #A2H has a 5,976 foot lateral and also has 26 frac stages. The Welhausen #A2H flowed back at a pressure of 4,500 psi and had an IP of 2,165 BOEPD. After a recent clean-out operation of both wells, including the removal of plugs associated with eight frac stages in the Welhausen #A2H, the wells were just turned back in line.

These two wells have two of the highest wellhead flowing pressures we have encountered to date in our Eagle Ford Shale development program. Their GORs (gas-oil-ratios) of 5,000 to 6,000 standard cubic feet per barrel are also the highest we have encountered, but these higher pressures and GORs were expected since these wells are also our deepest “down-dip” tests of the Eagle Ford Shale. These initial results imply that we are still in the volatile oil window. Longer term, additional testing and production history will help determine whether, at least in this area, the Upper Eagle Ford Shale and Lower Eagle Ford Shale are completely separate reservoirs.

With continued leasing contiguous to our current acreage positions, along with the continued success of our multi-well pad drilling efforts and closer well spacing, we anticipate that, over time, additional wells will be added to our approximate 1,510 well drilling inventory.

Below are the results and statistics for recent Eagle Ford Shale wells:

Full-Year 2014 Guidance

Our 2014 capital expenditures are expected to range between $595 and $653 million, an increase of $13 to $20 million from previous guidance. This reflects an increase in lease acquisition capital expenditures to $60 to $83 million from previous guidance of $40 to $70 million. Other 2014 guidance remains unchanged.

Please see the Guidance Table included in this release for guidance estimates for full-year 2014. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Explanation of Non-GAAP Cash Margin per BOE

Cash Margin per BOE is a non-GAAP financial measure which represents total product revenues less total direct operating expenses, excluding share-based compensation expenses. Cash Margin per BOE is equal to cash margin divided by total equivalent crude oil, NGL and natural gas production. Cash Margin per BOE is not adjusted for the impact of hedges. Cash Margin per BOE is not a measure of financial performance under GAAP and should not be considered as an alternative to operating income. We believe that Cash Margin per BOE is an important measure that can be used by security analysts and investors to evaluate our cash operating margin and to compare it to other oil and gas companies, as well as for comparisons to other time periods.

First Quarter 2014 Conference Call

A conference call and webcast, during which management will discuss first quarter 2014 financial and operational results, is scheduled for Tuesday, May 13, 2014 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 3581559), 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 3581559. 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 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 south and east Texas. 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, or 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 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 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 2014. 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 $10.00 per barrel increase or decrease in the crude oil price, operating income for the final three quarters of 2014 would increase or decrease by approximately $41.0 million. In addition, 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 final three quarters of 2014 would increase or decrease by approximately $10.6 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.