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 THIRD QUARTER 2012 RESULTS;

PROVIDES UPDATES OF OPERATIONS AND FULL-YEAR 2012 GUIDANCE;

PROVIDES PRELIMINARY 2013 GUIDANCE

FIFTH STRAIGHT QUARTER OF ADJUSTED EBITDAX AT OR ABOVE $60 MILLION

OIL / LIQUIDS REPRESENTED 52 PERCENT OF PRODUCTION AND 84 PERCENT OF PRODUCT REVENUES DURING THE QUARTER

34 PERCENT INCREASE IN OIL PRODUCTION OVER THE PRIOR YEAR QUARTER

RADNOR, PA (BusinessWire) October 31, 2012 - Penn Virginia Corporation (NYSE: PVA) today reported results for the three months ended September 30, 2012, provided updates of operations and full-year 2012 guidance and provided preliminary guidance for 2013.

Third Quarter 2012 Highlights

Third quarter 2012 results compared to the third quarter of 2011 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.

Recent Eagle Ford operational highlights are as follows:

Management Comment

H. Baird Whitehead, President and Chief Executive Officer stated, “Our third quarter results met our expectations, with Adjusted EBITDAX at or above $60 million for the fifth consecutive quarter. We believe our cash operating margin per unit of production is among the best of our small cap peers. We have had excellent well results in the Eagle Ford Shale and are pleased with our recent Eagle Ford Shale acreage additions and increases to our drilling inventory. The recent addition of the third rig in the Eagle Ford Shale play will allow us to resume sequential crude oil as well as overall production growth, on a pro forma basis, as we enter 2013. Recent acreage additions and derisking of our Lavaca County, Texas acreage now provide a greater than six-year inventory of drilling locations for a three-rig program.

“Since July 31^st, we have sold our Appalachian assets, completed concurrent offerings of $161 million of preferred and common equity and received a $32 million federal income tax refund, significantly improving the strength of our balance sheet and financial liquidity. As a result, we are well positioned to fund our 2013 Eagle Ford Shale drilling program, on which we will continue to be focused.”

Third Quarter 2012 Financial and Operational Results

Pricing

Our third quarter 2012 realized oil price of $99.45 per barrel was 14 percent higher than the $87.03 per barrel price in the prior year quarter. Our third quarter 2012 realized NGL price of $32.94 per barrel was 31 percent lower than the $48.00 per barrel price in the prior year quarter. Our third quarter 2012 realized natural gas price of $2.72 per thousand cubic feet (Mcf) was 36 percent lower than the $4.24 per Mcf price in the prior year quarter. Adjusting for oil and gas hedges, our third quarter 2012 effective oil price was $107.53 per barrel, and our effective natural gas price was $3.77 per Mcf, or increases of $8.08 per barrel and $1.05 per Mcf over the realized prices.

Overview of Financial Results

The operating loss in the third quarter of 2012 was $24.5 million, compared to the $9.0 million loss in the prior year quarter. The increase in loss of $15.5 million was due primarily to a $17.3 million increase in charges during the third quarter of 2012 related to firm transportation commitments for divested Appalachian assets and a $5.7 million decrease in total revenues, partially offset by a $7.5 million decrease in other operating expenses. Oil and NGL revenues were $63.7 million in the third quarter of 2012, 33 percent higher than the $47.8 million in the prior year quarter. Oil and NGL revenues were 84 percent of product revenues in the third quarter of 2012, compared to 58 percent in the prior year quarter.

Production

As shown in the table below, production in the third quarter of 2012 was 9.0 Bcfe, or 98.1 MMcfe per day, a 24 percent decrease compared to 11.9 Bcfe, or 129.9 MMcfe per day, in the prior year quarter. Excluding production from the Appalachian assets sold in July 2012 and the Arkoma Basin assets sold in August 2011, production in the third quarter of 2012 was 8.3 Bcfe, or 90.5 MMcfe per day, and the production in the prior year quarter was 9.2 Bcfe, or 100.0 MMcfe per day. The 0.9 Bcfe, or nine percent, decrease in pro forma production was the result of a 1.6 Bcfe, or 31 percent, decrease in natural gas production due to reduced natural gas drilling since mid-2010, partially offset by a 127 MBO (0.8 Bcfe), or 20 percent, increase in oil and NGL production due primarily to drilling in the Eagle Ford Shale since early 2011. As a percentage of total equivalent production, oil and NGL volumes were 52 percent in the third quarter of 2012 compared to 33 percent in the prior year quarter. Oil production increased 34 percent from 427 MBO in the prior year quarter to 573 MBO in the third quarter of 2012.

Note - Numbers may not add due to rounding

Operating Expenses

Third quarter 2012 total direct operating expenses decreased $1.3 million, or approximately five percent, to $24.3 million, or $2.69 per Mcfe produced, compared to $25.6 million, or $2.14 per Mcfe produced, in the prior year quarter.

Exploration expense decreased $10.0 million, or 52 percent, to $9.3 million in the third quarter of 2012 from $19.3 million in the prior year quarter. The decrease was due primarily to a $2.7 million decrease in unproved property amortization, a $2.8 million decrease in geological and geophysical costs and a 2011 charge of $4.8 million for a contract termination.

Depreciation, depletion and amortization (DD&A) expense increased by $4.0 million, or nine percent, to $49.3 million, or $5.47 per Mcfe produced, in the third quarter of 2012 from $45.3 million, or $3.80 per Mcfe produced, in the prior year quarter, due primarily to higher DD&A costs attributable to our Eagle Ford Shale oil wells and reserve revisions associated with our gas assets.

Capital Expenditures

During the third quarter of 2012, capital expenditures were approximately $85 million, compared to $114 million in the prior year quarter, consisting of:

Comparison of Third Quarter of 2012 to Second Quarter of 2012

As shown in the table above, production in the third quarter of 2012 of approximately 9.0 Bcfe, or 98.1 MMcfe per day, was 1.7 Bcfe, or 19.0 MMcfe per day, less than in the second quarter of 2012 due primarily to a 1.5 Bcfe decline in natural gas production as a result of the Appalachian sale and natural declines, as well as lower NGL production in the Mid-Continent associated with ethane rejection and reduced natural gas production. Crude oil production was essentially flat on a sequential basis as a result of the reduction in the rig count in the Eagle Ford Shale from three rigs to two rigs earlier in the year. We expect crude oil production to decrease slightly for the fourth quarter, after which we expect oil production to begin increasing in the first quarter of 2013 due to contributions associated with the third rig. During the third quarter of 2012, total product revenues were flat at approximately $76 million compared to the prior quarter as the decline in total production was offset by higher realized oil and gas prices. Due to flat sequential direct operating expenses of approximately $24 million in both quarters, increased cash settlements of derivatives in the third quarter and despite the sale of Appalachia at the end of July, third quarter Adjusted EBITDAX of approximately $61 million was slightly higher than the approximately $60 million in the prior quarter.

Operational Update

Eagle Ford Shale

During the third quarter of 2012, we drilled six (5.0 net) operated wells in the Eagle Ford Shale, all of which were successful. Since early August, we have completed eight (6.7 net) Eagle Ford Shale wells and acquired one (1.0 net) Eagle Ford Shale well, bringing the total to 59 (49.1 net) producing wells, with one (0.9 net) well being completed and the 61^st through 63^rd wells being drilled. The average peak gross production rate per well for the 49 wells we completed with full-length laterals was 986 BOEPD. The initial 30-day average gross production rate for 45 of these 49 wells with a 30-day production history was 656 BOEPD. Our Eagle Ford Shale production was approximately 6,300 net BOEPD during the third quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent.

Progress continues in reducing our drilling and completion costs. By sourcing our guar and proppant directly, we have stabilized our drilling and completion costs at $7.0 to $8.0 million per well in Gonzales County and, going forward, $8.5 to $9.5 million per well in Lavaca County, both depending on lateral length. We are also using only 100 percent high-strength white sand for proppant in Gonzales County and recently initiated the use of a mix of ceramic and high-strength white sand in Lavaca County.

Our full-year 2012 guidance anticipates the drilling of 33 (26.3 net) wells in the Eagle Ford Shale, including the wells drilled during the first nine months of 2012. As previously disclosed, we have increased our Eagle Ford Shale acreage position to approximately 40,000 gross (30,000 net) acres with a drilling inventory of up to approximately 285 locations. Efforts continue to expand our Eagle Ford Shale position through additional leasing and selective acquisitions.

Mid-Continent

During the third quarter of 2012, we drilled four (1.1 net) non-operated wells in the Granite Wash; one (0.5 net) well was successful, with final results not yet established on three (0.6 net) wells. We experienced operational problems while drilling our first horizontal Viola Lime well in Jefferson County, Oklahoma and, as a result, shortened the well’s planned lateral length by approximately 3,000 feet. We concluded that the drilled lateral length of approximately 1,100 feet was sufficient to test the concept of the prospect and we stimulated the shortened lateral with a seven-stage acid frac. The production rate is less than 10 BOPD, on pump, which is much less than anticipated. The prospect is being re-evaluated with the possibility of drilling an additional well in 2013 or attempting a recompletion in an up-hole interval in the existing well. We have an acreage position of approximately 9,600 net acres in this play.

Full-Year 2012 Guidance

Full-year 2012 guidance highlights are as follows:

Please see the Guidance Table included in this release for guidance estimates for full-year 2012. These estimates are meant to provide guidance only and are subject to revision as our operating environment changes.

Preliminary Full-Year 2013 Guidance

As a result of recent equity offerings, the sale of our Appalachian assets and the receipt of a federal income tax refund, we expect to have over $300 million of available liquidity in the form of cash and equivalents and revolver availability as we enter 2013. Preliminarily, we estimate 2013 capital expenditures will range between $310 and $345 million, compared to the mid-point of 2012 capital expenditures guidance of $343 million. This range is contingent on our partner in Lavaca County participating in applicable Lavaca County wells that we plan to drill. During 2013, approximately 85 percent of our capital expenditures will be allocated to activity in Gonzales and Lavaca Counties. Preliminarily, full-year 2013 production is estimated to be approximately 34 to 37 Bcfe, compared to the mid-point of 2012 production guidance, pro forma for the sale of our Appalachian assets, of approximately 34 Bcfe. We estimate that 2013 oil and NGL production will range between 55 and 65 percent of total production. Full year crude oil production is expected to be approximately 25 percent higher in 2013 than the midpoint of 2012 production guidance, while fourth quarter 2013 oil production is expected to be approximately 40 percent higher than the midpoint of fourth quarter 2012 oil production guidance. Our expected cash flows in 2013, along with available liquidity as we enter 2013, are expected to be more than sufficient to fund 2013 capital expenditures.

Capital Resources and Liquidity

As of September 30, 2012, we had total debt with a carrying value of approximately $676 million ($682 million aggregate principal amount), consisting of $294 million of 10.375 percent senior unsecured notes due 2016 ($300 million principal amount), $300 million principal amount of 7.25 percent senior unsecured notes due 2019, approximately $5 million principal amount of 4.5 percent convertible senior subordinated notes due in November 2012 (classified as a current liability) and $77 million of borrowings under our revolving credit facility (Revolver). Our indebtedness at September 30, 2012 was approximately 46 percent of book capitalization and 2.7 times the latest twelve months’ Adjusted EBITDAX of $248 million. As a result of the $161 million issuance of preferred and common equity in October 2012, pro forma net debt at September 30, 2012 was approximately $516 million and net debt-to-Adjusted EBITDAX was approximately 2.1 times. Currently, we have no amounts borrowed under the Revolver, approximately $298 million of availability under the Revolver and approximately $50 million of cash on hand. We have no material debt maturities until 2016.

Explanation of Non-GAAP Gross Operating Margin per Mcfe

Gross operating margin is a non-GAAP financial measure under Securities and Exchange Commission (SEC) regulations which represents total product revenues less total direct operating expenses. Gross operating margin per Mcfe is equal to gross operating margin divided by total natural gas, crude oil and NGL production. Gross operating margin is not adjusted for the impact of hedges. We believe that gross operating margin per Mcfe 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.

Third Quarter 2012 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss third quarter 2012 financial and operational results, is scheduled for Thursday, November 1, 2012 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 10 minutes before the scheduled start of the conference call (use the passcode 4295337), 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 4295337. 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, Oklahoma, Mississippi and Pennsylvania. 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 and natural gas; our ability to develop, explore for, acquire and replace oil and 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, natural gas liquids 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 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 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 2012. These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes.