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 SECOND QUARTER 2015 RESULTS AND

PROVIDES UPDATES OF 2015 GUIDANCE AND OPERATIONS

RADNOR, PA (Globe Newswire) July 29, 2015 – Penn Virginia Corporation (NYSE: PVA) today reported financial results for the three months ended June 30, 2015 and provided updates of its operations and 2015 capital plan and guidance.

Key Highlights

Second quarter 2015 results compared, as applicable, to first quarter 2015 results were as follows:

Other recent highlights included:

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, “Second quarter revenues and Adjusted EBITDAX were higher than we had expected, despite continued low product prices. We continue to focus on decreasing our costs with combined unit production and G&A costs declining approximately 4% from the first quarter. In addition, the execution of our drilling and completion program continues to improve with our overall per well costs now 30% and 42% lower than in the fourth and third quarters of 2014, respectively.

“Our second quarter production came in below the lower end of second quarter guidance, primarily for two reasons: first, higher gathering line pressures curtailed production by an estimated 500 BOEPD and, second, the early-time performance of our recent Upper Eagle Ford program did not meet our expectations. The line pressure issue will be resolved soon as our midstream transporter is adding additional compression and, as described more fully below, we have taken steps to improve our completion design which we believe will improve well performance. We remain confident in the potential of the Upper Eagle Ford on our acreage. Nevertheless, we will be focusing our drilling effort for the time being to two-string Lower Eagle Ford in Gonzales County and northwestern Lavaca County, where rates of returns are optimized. This redirection of our drilling program to Gonzales County, where the initial potentials (IPs) and drilling and completion costs are somewhat less, has led us to reduce both capital expenditures and production guidance for the second half of 2015, as detailed later in this release.”

Mr. Whitehead concluded, “With the sale of East Texas, we have sufficient liquidity to execute the remainder of our 2015 program. Our focus now is developing a 2016 capital program relative to our expected liquidity such that, at the end of 2016, we will remain financially healthy.”

Second Quarter 2015 Results

Overview of Results

Operating loss was $41.0 million in the second quarter of 2015, compared to operating loss of $57.9 million in the first quarter of 2015. This $16.9 million improvement was due to a $9.1 million increase in product and other revenues and a $7.8 million decrease in operating expenses.

Net loss attributable to common shareholders for the second quarter was $86.2 million, or $1.19 per diluted share, compared to net loss of $63.2 million, or $0.88 per diluted share, in the prior quarter. The primary reason for the decrease was the non-cash $38.4 million increase in derivatives expense, which includes mark-to-market adjustments. Adjusted net loss attributable to common shareholders, a non-GAAP measure which includes our preferred stock dividend but excludes the effects of non-cash derivatives expense and other items that affect comparability to other periods, was $32.0 million, or $0.44 per diluted share, for the second quarter compared to a loss of $44.9 million, or $0.62 per diluted share, in the prior quarter. The primary reason for the improvement was the $16.9 million decrease in operating loss, partially offset by a $1.0 million increase in interest expense and a $2.7 million decrease in cash settlements of derivatives.

Production

As shown in the table below, total production in the second quarter of 2015 was 23,519 BOEPD, compared to 24,721 BOEPD in the first quarter of 2015, with a 1,131 BOEPD decrease in the Eagle Ford and a 71 BOEPD decrease in other areas. The decrease in production in the Eagle Ford, was primarily due to higher line pressure in sections of our gathering system, along with lower than expected early-time production performance from our recent Upper Eagle Ford drilling program.

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

Product Revenues

Total product revenues increased by $10.0 million, or 14%, to $83.1 million, or $38.84 per BOE, in the second quarter of 2015, from $73.1 million, or $32.87 per BOE, in the first quarter of 2015 due primarily to the 18% increase in the realized oil equivalent price, partially offset by a 4% decrease in daily production. Including derivatives, total product revenues were $118.0 million, or $55.12 per BOE, in the second quarter of 2015, compared to $110.6 million, or $49.72 per BOE, in the first quarter of 2015. For the second quarter, the realized oil price increased by 25%, the realized natural gas price decreased by 13% and the realized NGL price decreased by 1% compared to the first quarter of 2015.

Operating Expenses

As discussed below, second quarter 2015 total direct operating expenses, excluding share-based compensation and non-recurring expenses, decreased by $2.3 million to $32.1 million, or $14.99 per BOE produced, from $34.4 million, or $15.45 per BOE produced, in the first quarter of 2015.

Depletion, depreciation and amortization expense in the second quarter of 2015 decreased by $5.4 million to $85.4 million, or $39.91 per BOE, from $90.8 million, or $40.81 per BOE, in the first quarter.

We recorded an impairment charge of $1.1 million during the second quarter, attributable to tubular inventory and well materials.

Capital Expenditures

During the second quarter of 2015, capital expenditures were $94 million, a decrease of $53 million, or 36%, compared to $147 million in the first quarter of 2015, consisting of:

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of June 30, 2015, we had total debt of $1,287 million, consisting of $300 million principal amount of 7.25% senior unsecured notes due 2019, $775 million principal amount of 8.50% senior unsecured notes due 2020 and $212 million drawn under our revolving credit facility (Revolver). Together with cash and equivalents of $4 million and net of letters of credit of $2 million, our financial liquidity was $215 million at June 30, 2015. Pro forma liquidity, assuming the closing of the previously announced sale of our East Texas assets would have been $260 million, assuming a $30 million decrease to our borrowing base related to the assets to be divested.

Our total debt leverage ratio under the Revolver at June 30, 2015 was 3.7 times trailing twelve months’ Adjusted EBITDAX of $355 million. The maximum leverage ratio allowable during the second quarter of 2015 under the Revolver was 4.75 times. An additional covenant for credit exposure, defined as all outstanding borrowings under the Revolver plus any outstanding letters of credit, has a maximum allowable ratio of 2.75 times through March 31, 2017. At June 30, 2015, this ratio was 0.6 times. Pro forma total debt and credit exposure ratios, assuming the closing of the previously announced sale of our East Texas assets, were 3.6 times and 0.4 times, respectively.

During the second quarter, interest expense was $23.0 million, of which $21.8 million was cash interest expense, compared to $22.0 million, of which $20.9 million was cash interest expense in the first quarter. In addition, during the second quarter, we paid $6.1 million in preferred stock dividends, unchanged from the first quarter.

During the second quarter, derivatives expense was $15.5 million, compared to derivatives income of $22.9 million in the first quarter. Second quarter cash settlements of derivatives resulted in net cash receipts of $34.8 million, compared to $37.5 million of net cash receipts in the first 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. Currently, we have hedged 11,000 barrels of daily crude oil production during the second half of 2015, or about 80% to 90% of our expected oil production, at a weighted average floor/swap price of $89.86 per barrel. We have sold put options for 5,000 barrels of daily crude oil production during the second half of 2015, with all put options sold at a strike price of $70.00 per barrel. For 2016, we have hedged 6,000 barrels of daily crude oil production at a weighted average floor/swap price of $80.41 per barrel. We currently do not have any natural gas hedges.

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

Full-Year 2015 Guidance Update and Preliminary 2016 Guidance

Full-year 2015 guidance highlights are as follows:

Please see the Guidance Table included in this release for guidance estimates for third and fourth quarter and full-year 2015.

Preliminarily, and based on expected conditions in the crude oil market, specifically $55 to $60 per barrel WTI crude oil pricing, we expect to spend $200 to $250 million in capital expenditures during 2016, with fourth quarter 2016 oil production up to approximately 10% higher than the midpoint of fourth quarter 2015 oil production guidance. The 2016 preliminary capital budget will be funded by anticipated year-end 2015 liquidity and 2016 cash flows from operating activities. 2015 estimates and 2016 preliminary estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Eagle Ford Shale Operational Update

Second Quarter 2015 Update

Second quarter production from our Eagle Ford operations was 20,259 BOEPD, a 5% decrease from the 21,390 BOEPD produced in the first quarter of 2015. Approximately 68% of our second quarter Eagle Ford production was from crude oil, 17% was from NGLs and 15% was from natural gas, unchanged from the first quarter of 2015. As explained in this release, the decrease was primarily attributable to higher line pressure in sections of our midstream gathering systems and lower than expected early-time performance of Upper Eagle Ford wells during the second quarter.

Well Cost Reductions

Average gross well costs for all wells drilled and completed during the second quarter of 2015 declined by approximately $1.7 million, or 19%, to $6.9 million from approximately $8.6 million for wells drilled and completed in the first quarter of 2015. This lower overall well cost equates to approximately a 30% and 42% decrease in well costs since the fourth quarter and third quarters of 2014, respectively. More specifically, the cost of our most recent two-string Lower Eagle Ford wells averaged $5.3 million, while our most recent three-string wells averaged $8.0 million.

Average drilling costs for the second quarter of 2015 decreased 24% and 30% compared to the fourth and third quarters of 2014, respectively, driven by enhanced efficiencies and increased average rates of penetration. Average completion costs for wells over those same time intervals declined by 34% and 51%, respectively. Approximately half of the decreases in completion costs can be attributed to ongoing optimization and increased efficiencies, while the other half can be attributed to improved pricing.

Recent Eagle Ford Well Results

Below are the results and statistics for Eagle Ford wells over the past five quarters: ⁽²⁾

Since the end of the first quarter of 2015, we have turned in line 20 (14.8 net) operated wells. As a group, these 20 wells had an average IP rate of 823 BOEPD over an average of 24.0 frac stages, with 79% of production from crude oil. Ten of these wells were drilled into the Lower Eagle Ford and had an average IP rate of 1,027 BOEPD over and an average of 24.1 frac stages. The other ten of these wells were drilled into the Upper Eagle Ford and had an average IP rate of 618 BOEPD over and an average of 23.8 frac stages. Of these 20 wells, 12 wells with sufficient production history had a 30-day average rate of 596 BOEPD, with 76% of production from crude oil. The average amount of proppant per stage for these 20 wells was approximately 290,000 pounds and average amount of proppant per lateral foot was approximately 1,175 pounds, as discussed below.

Evolving Completion Design

Despite the disappointing IP rates of some of our recent Upper Eagle Ford wells, we continue to believe that the Upper Eagle Ford has significant potential across much of our acreage. Furthermore, we have identified certain factors which we believe contributed to our recent less-than-expected well results in the Upper Eagle Ford. First, in the first half of 2015, we reduced the amount of proppant pumped per foot of lateral. A detailed analysis has yielded evidence that there is a positive correlation between the amount of proppant pumped and well performance, so we intend to increase proppant in the third quarter. In addition, we have drilled some excellent Upper Eagle Ford wells in the general vicinity of other wells that had disappointing results, with the difference being that the better performing wells had alternating laterals in the Upper and Lower Eagle Ford that were then “zipper” fracked. Finally, we also intend to transition to “slickwater” stimulations. We believe that using this more complex completion technique of alternating laterals, increasing proppant pumped per stage and transitioning to slickwater stimulations in combination will improve our well results.

Drilling Program Outlook

For the remainder of 2015 and due primarily to continued low oil prices, we are discontinuing any Upper Eagle Ford drilling and are focusing our efforts drilling on less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where our economics are optimized. Preliminarily, we expect to resume multi-well pad drilling of alternating Upper and Lower Eagle Ford wells in 2016.

Second Quarter 2015 Conference Call

A conference call and webcast, during which management will discuss second quarter 2015 financial and operational results, is scheduled for Thursday, July 30, 2015 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 59450442), or via webcast with presentation slides 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 59450442. 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 the Eagle Ford Shale in south 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, 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, or the Revolver; 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 oil and gas companies; our ability to successfully monetize select assets and repay our debt; leasehold terms expiring before production can be established; environmental obligations, costs and 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; compliance with debt covenants; 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 the ability of these parties to meet their future obligations; compliance with and changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters; physical, electronic and cybersecurity breaches; 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. All subsequent written and oral forward-looking statements attributable to PVA or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. 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, except as may be required by applicable law.

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 2015.

The guidance reflects the closing of the pending sale of East Texas assets during the third quarter of 2015

These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes.