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 RECORD QUARTERLY OIL PRODUCTION AND

PRELIMINARY 2014 OIL PRODUCTION GROWTH GUIDANCE OF 65 TO 85 PERCENT

CORE EAGLE FORD SHALE POSITION EXPANDED TO 67,000 NET ACRES

DRILLING INVENTORY INCREASED TO APPROXIMATELY 890 LOCATIONS

MID-YEAR 2013 EAGLE FORD SHALE PROVED RESERVES OF 51 MMBOE AND 3P RESERVES OF 170 MMBOE

CONTINUED EXCELLENT DRILLING RESULTS IN THE EAGLE FORD SHALE

BORROWING BASE INCREASED FROM $350 MILLION TO $425 MILLION

FINANCIAL LIQUIDITY OF APPROXIMATELY $330 MILLION

RADNOR, PA (Globe Newswire) October 30, 2013 – Penn Virginia Corporation (NYSE: PVA) today reported financial results for the three months ended September 30, 2013, provided updates of its operations and 2013 guidance, and provided preliminary 2014 guidance.

Third Quarter 2013 Highlights

Third quarter 2013 financial results, as compared to second quarter 2013 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.

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “In the third quarter, our operating cash flows and margins remained strong as a result of the continued growth in oil production, as well as lower unit operating costs. Despite this growth, our production and revenues increased less than expected during the third quarter due to several issues associated with the outside operated Eagle Ford Shale program. Our non-operated partner recently reduced its rig count from two to one and, as a result, we have increased our operated drilling rig count by one rig. We continue to expect our 2013 results to remain within our previous guidance. The increase in operated activity during the fourth quarter will have a negligible production and cash flow effect in 2013 but will, of course, provide much more of a benefit in 2014. We now expect 2014 oil production growth of between 65 and 85 percent over 2013 with the assumption that five operated rigs and one outside operated rig will be dedicated to the Eagle Ford Shale drilling program.

“Additional leasing in the Eagle Ford Shale at a cost of approximately $1,600 per net acre has further increased our net acreage and we continue to have success in finding additional opportunities to grow our position. Therefore, our stated 100,000 net acre goal remains intact and achievable at attractive costs. As a result of and in conjunction with successful downspaced drilling, we have increased our estimated drilling inventory by about 20 percent to our current estimate of approximately 890 locations.

“During the third quarter, our well costs decreased and well productivity increased as a result of lower completion costs, the increased use of multi-well pads and the use of “zipper fracs,” which have contributed to greater productivity per well and per frac stage. We continue to consider additional techniques to further optimize our well results and value.

“Our balance sheet remains sound with approximately $330 million of financial liquidity. We recently had our borrowing base increased from $350 to $425 million as the value-added drilling in the Eagle Ford Shale has beneficially impacted our reserve value. We expect to fund our capital programs over the next few years with increasing operating cash flows, net proceeds from asset sales and borrowings under our revolver, with the goals of decreasing our leverage ratio and increasing our liquidity over this same timeframe.”

Third Quarter 2013 Results

Overview of Financial Results

The $24.4 million of operating income in the third quarter, excluding $132.2 million of impairment expense, was an $18.8 million improvement over $5.6 million in the second quarter, excluding $2.4 million of acquisition transaction expenses. This improvement was due primarily to an $11.9 million increase in total product revenues, a $3.9 million decrease in exploration expense, a $1.9 million decrease in depreciation, depletion and amortization (DD&A) expense and a $1.7 million decrease in share-based compensation expense. The effect of these changes was partially offset by a $0.6 million increase in total direct operating expenses, excluding acquisition transaction expenses.

Product Revenues

Total product revenues were $121.6 million in the third quarter, an 11 percent increase compared to $109.7 million in the second quarter, due primarily to a seven percent increase in average product pricing to $67.33 per BOE from $62.78 per BOE, as well as a three percent increase in equivalent production. Oil and NGL revenues were $108.8 million in the third quarter, a 15 percent increase compared to $94.2 million in the second quarter, due to an eight percent increase in production and seven percent increase in oil and NGL prices. Oil and NGL revenues were 89 percent of product revenues in the third quarter, compared to 86 percent in the second quarter.

Operating Expenses

As discussed below, third quarter total direct operating expenses increased $0.6 million to $29.8 million, or $16.47 per BOE produced, compared to $29.2 million, excluding $2.4 million of acquisition transaction expenses, or $16.68 per BOE, in the second quarter.

Exploration expense decreased to approximately $4.0 million in the third quarter from $7.8 million in the second quarter. The decrease was due primarily to reduced amortization on unproved properties in the Eagle Ford Shale.

DD&A expense decreased by $1.9 million to $62.5 million, or $34.57 per BOE, in the third quarter of 2013 from $64.3 million, or $36.80 per BOE, in the second quarter due primarily to the increase in mid-year 2013 Eagle Ford Shale reserves.

In the third quarter of 2013, we recognized $132.2 million of impairment expense, including the Granite Wash in the Mid-Continent region ($121.8 million), the Marcellus Shale in Pennsylvania ($9.5 million) and the Selma Chalk in Mississippi ($0.9 million), in each case due primarily to market declines in commodity prices.

Production

Production in the third quarter was 1.8 MMBOE, or 19,638 BOEPD, compared to 1.7 MMBOE, or 19,209 BOEPD, in the second quarter. As a percentage of total equivalent production, oil and NGL volumes were 67 percent in the third quarter of 2013, compared to 64 percent in the second quarter. As discussed further below in the release, we now expect outside operated production volumes for the second half of 2013 to be approximately 0.2 MMBOE less than previous expectations, causing essentially all of the variance from the midpoint of our previous production guidance. We recently added an operated rig in an attempt to mitigate the shortfall and increase fourth quarter 2013 production, as well as to benefit 2014 production.

The table below shows quarterly production detail.

Notes—Numbers may not add due to rounding.

Capital Expenditures

During the third quarter, capital expenditures were approximately $120 million, a decrease of 18 percent compared to $145 million in the second quarter, consisting of:

The approximate $25 million decrease in capital expenditures from the second quarter to the third quarter was attributable to lower lease acquisition, lower drilling and completion costs, and decreased spending on production facilities.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of September 30, 2013, we had total debt of $1,203 million, consisting of $300 million principal amount of 7.25 percent senior unsecured notes due 2019, $775 million of 8.50 percent senior unsecured notes due 2020 and $128 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 $340 million.

In October, the borrowing base under the Revolver was increased from $350 million to $425 million, with PVA electing to receive commitments for $400 million. As a result, together with cash and cash equivalents of $38 million, our pro forma liquidity, including the uncommitted amount, increased to approximately $330 million at September 30, 2013. The next borrowing base redetermination is scheduled for the spring of 2014.

During the third quarter, interest expense was $20.2 million, of which $19.3 million was cash interest expense, compared to $21.8 million in the second quarter.

During the third quarter, derivatives loss was $24.0 million, compared to a derivatives income of $8.6 million in the second quarter. Third quarter 2013 cash settlements of derivatives resulted in net cash outlays of $4.2 million, compared to $2.2 million of net cash receipts in the second 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 9,400 barrels of daily crude oil production in the fourth quarter of 2013, or approximately 79 percent of the midpoint of guidance for fourth quarter crude oil production, at a weighted average floor/swap price of $94.69 per barrel. For 2014, we have hedged approximately 8,500 barrels of daily crude oil production, or approximately 50 percent of the midpoint of preliminary guidance, at a weighted average floor/swap price of $93.49 per barrel.

We have also hedged approximately 25,000 MMBtu of daily natural gas production in the fourth quarter of 2013, or approximately 69 percent of the midpoint of guidance for fourth quarter natural gas production, at a weighted average floor/swap price of $3.82 per MMBtu. For 2014, we have hedged approximately 12,500 MMBtu of daily natural gas production, or approximately 33 percent of the midpoint of preliminary guidance, at a weighted average floor/swap price of $4.17 per MMBtu.

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

Eagle Ford Shale Operational Update

Net production from the Eagle Ford Shale was 12,489 BOEPD in the third quarter, an increase of nine percent from 11,476 BOEPD in the second quarter. During the third quarter, we completed 16 (9.7 net) operated wells and participated in the completion of one (0.4 net) outside operated well. In the Eagle Ford Shale, we have a total of 158 (105.4 net) producing wells, 10 (4.8 net) operated wells completing or waiting on completion and six (3.2 net) operated wells being drilled. During the third quarter, only one outside operated well was turned in line and the non-operated rig count decreased from two rigs to one rig. As a result, we have responded by increasing our operated rig count by one rig and, as discussed in the preliminary 2014 guidance section below, we now expect to have five operated rigs and one non-operated rig drilling during 2014.

In the fourth quarter, we also expect to further test the upper Eagle Ford Shale with a two-well pad, one well of which will be drilled in the lower Eagle Ford Shale and one well of which will be drilled in the upper Eagle Ford Shale. This test will help determine whether the upper Eagle Ford Shale is a separate reservoir from the lower Eagle Ford Shale, which is the interval in which we typically complete our wells.

Set forth below are the results and statistics for recent Eagle Ford Shale wells:

Of our 19 most recent operated wells, 16 were drilled on six pads, with an average effective nominal spacing of approximately 70 acres. With continued leasing contiguous to our current acreage positions, along with the continued success of our pad drilling efforts and closer well spacing, we anticipate that, over time, additional wells will be added to our approximate 890 well drilling inventory.

Fourth Quarter 2013 Guidance

Updated guidance highlights that impact the fourth quarter of 2013 are as follows:

Please see the Guidance Table included in this release for guidance estimates for fourth quarter and full-year 2013. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Preliminary Full-Year 2014 Guidance

As a result of the recent borrowing base increase, we expect to have approximately $250 million of available liquidity in the form of cash and cash equivalents and borrowing base availability as we enter 2014. This liquidity estimate does not include any potential net proceeds from the sale of our Eagle Ford Shale natural gas midstream and gas lift assets. We recently received bids from a number of parties for these assets which exceeded our minimum expectation. The sale of additional assets, including the right to build an Eagle Ford Shale oil gathering system, may be pursued in the first half of 2014.

As a result of the estimated year-end 2013 liquidity, together with expected 2014 cash flows and the potential net proceeds from one or more divestitures, we believe that we will have more than sufficient funds for our 2014 capital expenditures program, which we preliminarily estimate will range between $510 and $540 million, roughly equal to the revised 2013 capital expenditures guidance range of $500 to $530 million. This 2014 range assumes a drilling program utilizing a total of six drilling rigs in the Eagle Ford Shale, five of which would be operated and one of which would be outside operated. Correspondingly, full-year 2014 production is preliminarily estimated to range between approximately 9.0 and 10.0 MMBOE, or 24,600 to 27,400 BOEPD, which is 30 to 45 percent higher than the mid-point of 2013 production guidance of approximately 6.9 MMBOE, or 18,900 BOEPD. We estimate that 2014 oil and NGL production will be approximately 75 percent of total production. Full year 2014 crude oil production is expected to be between 65 and 85 percent higher than the midpoint of 2013 production guidance, while fourth quarter 2014 oil production is expected to be between 40 and 70 percent higher than the midpoint of fourth quarter 2013 oil production guidance. These early estimates are meant to provide guidance only and are subject to revision as our operating and the product pricing environments may change.

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, excluding acquisition transaction 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.

Explanation of Non-GAAP PV-10 Value

PV-10 value is the estimated future net cash flows from estimated proved reserves discounted at an annual rate of 10 percent before giving effect to income taxes. The standardized measure is the after-tax estimated future cash flows from estimated proved reserves discounted at an annual rate of 10 percent, determined in accordance with generally accepted accounting principles (GAAP). We use PV-10 value as one measure of the value of our estimated proved reserves and to compare relative values of proved reserves among exploration and production companies without regard to income taxes. We believe that securities analysts and rating agencies use PV-10 value in similar ways. Our management believes PV-10 value is a useful measure for comparison of proved reserve values among companies because, unlike standardized measure, it excludes future income taxes that often depend principally on the characteristics of the owner of the reserves rather than on the nature, location and quality of the reserves themselves. We cannot reconcile PV-10 value to the standardized measure at this time because final income tax information for mid-year 2013 is not available.

Third Quarter 2013 Conference Call

A conference call and webcast, during which management will discuss third quarter 2013 financial and operational results, is scheduled for Thursday, October 31, 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 33059048), 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 33059048. 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: 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.

  Vice President, Corporate Development

  Ph: (610) 687-7531 Fax: (610) 687-3688

  E-Mail: invest@pennvirginia.com

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 fourth quarter and 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.

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 $3.2 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 $10.2 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.