Ranger Oil 8K Results of Operations and Financial Condition | ROCC 9 May 13

Exhibit 99.1

LOGO

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:

•

Product revenues from the sale of oil, natural gas liquids (NGLs) and natural gas were $82.2 million, or $57.61 per barrel of oil equivalent (BOE), increases of eight percent compared to $76.0 million, or $53.48 per BOE

•

Oil and NGL revenues were $70.2 million, or 85 percent of product revenues, an increase of 11 percent compared to $63.2 million, or 83 percent of product revenues

•

Operating margin, a non-GAAP (generally accepted accounting principles) measure, was $38.55 per BOE, a decrease of two percent compared to $39.29 per BOE

•

Operating loss was $3.0 million, compared to a loss of $6.0 million, excluding impairments in the fourth quarter of 2012

•

Adjusted EBITDAX, a non-GAAP measure, was $60.3 million, a decrease of three percent compared to $62.3 million

•

Loss attributable to common shareholders (which includes our preferred stock dividend) was $18.1 million, or $0.33 per diluted share, compared to a loss of $56.1 million, or $1.05 per diluted share

•

Adjusted loss attributable to common shareholders (which includes our preferred stock dividend), a non-GAAP measure which excludes the effects of certain costs and other gains or losses that affect comparability to other periods, was $10.4 million, or $0.19 per diluted share, compared to a loss of $11.8 million, or $0.22 per diluted share

Recent operational highlights were as follows:

•

Production of 1.4 million BOE (MMBOE), or 15,857 BOE per day (BOEPD), in the first quarter of 2013, compared to 1.4 MMBOE, or 15,444 BOEPD, in the fourth quarter of 2012 (a three percent increase in the daily rate)

•

Eagle Ford Shale net production was 7,523 BOEPD in the first quarter of 2013, compared to 6,872 BOEPD in the fourth quarter of 2012 (a nine percent increase in the daily rate)

•

Oil and NGL production was 58 percent of production in the first quarter of 2013 compared to 56 percent in the fourth quarter of 2012

•

Including the Eagle Ford Shale assets acquired from Magnum Hunter Resources Corporation (NYSE: MHR) in April 2013, we currently 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

•

The average peak gross production rate per well for the 104 (76.1 net) operated wells completed to date was 1,069 BOEPD. The initial 30-day average gross production rate for the 98 of these 104 wells with a 30-day production history was 683 BOEPD

•

The average peak gross production rate per well for the 15 most recent operated wells was 1,399 BOEPD. The initial 30-day average gross production rate for the 11 of these 15 wells with a 30-day production history was 830 BOEPD. These recent production improvements are likely attributable to a majority of these recent wells being located in Lavaca County, which is structurally downdip of Gonzales County and, therefore, have an increased reservoir pressure and higher oil and gas production rates. In addition, many of these wells had longer lateral lengths and an increased number of frac stages. Going forward, our drilling program in Lavaca County will primarily include wells with longer lateral lengths.

•

Currently, we have a total of approximately 80,200 (54,200 net) acres in the Eagle Ford Shale, approximately 66,900 (47,700 net) of which are operated

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.

•

Lease operating expenses increased by $1.2 million to $7.8 million, or $5.47 per BOE produced, from $6.6 million, or $4.68 per BOE produced, in the fourth quarter of 2012 due primarily to higher paraffin and corrosion inhibitor chemical costs and higher water disposal, compressor, repair and maintenance and other miscellaneous costs associated primarily with our increasing growth in the Eagle Ford Shale.

•

Gathering, processing and transportation expenses increased by $1.1 million to $3.6 million, or $2.51 per BOE produced, from $2.5 million, or $1.78 per BOE produced, in the fourth quarter of 2012 due primarily to higher gas production and related processing costs associated with NGLs in the Eagle Ford Shale in Lavaca County

•

Production and ad valorem taxes increased by $3.2 million to $5.9 million, or 7.2 percent of product revenues, from $2.7 million, or 3.6 percent of product revenues, in the fourth quarter of 2012 due primarily to our production increases in the Eagle Ford Shale

•

General and administrative expenses, excluding share-based compensation, increased by $1.6 million to $9.9 million, or $6.91 per BOE produced, from $8.3 million, or $5.82 per BOE produced, in the fourth quarter of 2012 due primarily to prior year incentive compensation and related payroll tax and benefit costs paid in the first quarter of 2013

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.

Total and Daily Equivalent Production for the Three Months Ended

Region / Play Type

Mar. 31,
2013

Dec. 31,
2012

Mar. 31,
2012

Mar. 31,
2013

Dec. 31,
2012

Mar. 31,
2012

(in MBOE)

(in BOEPD)

Texas

954

944

891

10,599

10,265

9,787

Cotton Valley/Other

195

216

235

2,169

2,352

2,583

Haynesville Shale

131

906

1,041

1,444

Eagle Ford

677

632

524

7,523

6,872

5,761

Appalachia

344

3,782

Mid-Continent

271

266

358

3,015

2,892

3,934

Mississippi

196

203

220

2,177

2,209

2,413

Totals

1,427

1,421

1,812

15,857

15,444

19,916

Pro Forma Totals⁽¹⁾

1,427

1,421

1,491

15,857

15,444

16,380

⁽¹⁾	Pro forma to exclude production from the Appalachian assets sold in July 2012.

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:

•

$87 million for drilling and completion activities;

•

$4 million for seismic, pipeline, gathering and facilities; and

•

$5 million for leasehold acquisitions, field projects and other

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.


						Peak Gross Daily Production Rates⁽²⁾				30-Day Average Gross Daily Production Rates⁽²⁾
Well Name	County	Lateral Length		Frac Stages		Oil Rate		Equivalent Rate		Oil Rate		Equivalent Rate
		Feet				BOPD		BOEPD		BOPD		BOEPD
Operated wells
Arledge Ranch #1H	Gonzales		4,150		21		1,015		1,117		662		728
Zebra Hunter #1H	Lavaca		5,410		22		1,995		2,145		963		1,084
Rhino Hunter #1H	Lavaca		6,296		27		2,033		2,219		1,071		1,209
Raab #1H	Lavaca		5,450		22		808		1,046		638		832
R. Washington #1H	Gonzales		3,702		19		744		805		555		611
Barraza #1H	Lavaca		3,952		16		574		680		391		474
Moose Hunter #3H	Lavaca		6,062		21		1,509		1,676		833		914
Technik #1H	Lavaca		4,452		18		1,136		1,445		597		789
Targac #1H	Lavaca		4,300		16		736		865		410		520
Fojtik #1H	Lavaca		4,202		17		865		1,209		497		684
Martinsen #1H	Lavaca		5,630		23		1,199		1,878		819		1,291
Othold #1H	Lavaca		5,432		17		1,052		1,625		—		—
Elk Hunter #1H	Lavaca		6,107		22		1,232		1,303		—		—
Elk Hunter #2H	Lavaca		6,664		25		1,422		1,514		—		—
Elk Hunter #3H	Lavaca		6,080		21		1,339		1,456		—		—

Averages (15 most recent operated wells)			5,193		20		1,177		1,399		676		830
Averages (all 104 operated wells)			4,488		18		959		1,069		600		683

Non-operated wells⁽³⁾
JP Ranch F #2H	Gonzales		6,040		24		534		552		390		418
Dorothy Springs #1H	Gonzales		6,739		19		587		621		527		559
JP Ranch F #1H	Gonzales		6,105		20		517		560		377		410

⁽²⁾	Wellhead rates only; the natural gas associated with these wells is yielding between 165 and 315 barrels of NGLs per million cubic feet in Gonzales and Lavaca Counties. BOPD is defined as barrels of oil per day.

⁽³⁾	Excludes three wells for which MHR went non-consent and in which we have a 2.5 percent overriding royalty (12.5 percent working interest after payout).

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:

•

Production is expected to be 6.7 to 7.3 MMBOE, or approximately 18,200 to 20,000 BOEPD, compared to previous guidance of 6.5 to 7.2 MMBOE, or approximately 17,800 to 19,600 BOEPD.

•

Crude oil production is expected to increase by 60 to 78 percent over 2012 levels, compared to previous guidance of 57 to 76 percent growth. Crude oil and NGLs are expected to comprise 65 to 69 percent of total production, unchanged compared to previous guidance.

•

Our production during March 2013 was approximately 15,700 BOEPD, 41 percent of which was crude oil and 17 percent of which was NGLs. Production during March 2013 for the acquired MHR assets was approximately 2,700 BOEPD, 91 percent of which was crude oil and five percent of which was NGLs. The production for the MHR assets declined from February to March due to natural declines and a lack of completion activity.

•

Product revenues, excluding the impact of any hedges, are expected to be $414 to $469 million, compared to previous guidance of $403 to $447 million.

•

Crude oil and NGL product revenues are expected to be 86 to 89 percent of total product revenues, compared to previous guidance of 88 to 90 percent.

•

Settlements of current commodity hedges are expected to result in cash receipts of approximately $13 million in 2013, unchanged compared to previous guidance.

•

Adjusted EBITDAX, a non-GAAP measure, is expected to be $300 to $360 million, compared to previous guidance of $295 to $350 million.

•

Capital expenditures are expected to be $445 to $505 million, compared to previous guidance of $432 to $482 million.

•

Approximately 94 percent of capital expenditures are expected to be allocated to the Eagle Ford Shale.

•

2013 capital expenditures include $400 to $450 million for drilling and completions ($390 to $430 million of previous guidance), $23 to $30 million for lease acquisitions ($25 to $31 million of previous guidance) and $22 to $25 million for pipeline, gathering, seismic and facilities (unchanged from previous guidance).

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.

******

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 atwww.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.


Contact:		James W. Dean
		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)


	Three months ended March 31,
	2013			2012
Revenues
Crude oil	$	63,058		$	58,723
Natural gas liquids (NGLs)		7,127			9,071
Natural gas		12,039			14,886

Total product revenues		82,224			82,680
Gain (loss) on sales of property and equipment, net		(549	)		756
Other		1,523			975

Total revenues		83,198			84,411
Operating expenses
Lease operating		7,805			9,143
Gathering, processing and transportation		3,579			4,154
Production and ad valorem taxes		5,959			3,580
General and administrative (excluding equity-classified share-based compensation) (a)		9,858			10,526

Total direct operating expenses		27,201			27,403
Share-based compensation - equity classified awards (b)		1,085			1,615
Exploration		6,295			7,998
Depreciation, depletion and amortization		51,576			50,817

Total operating expenses		86,157			87,833


Operating loss		(2,959	)		(3,422	)

Other income (expense)
Interest expense		(14,479	)		(14,774	)
Derivatives		(7,761	)		(305	)
Other		27			1


Loss before income taxes		(25,172	)		(18,500	)
Income tax benefit		8,789			6,601

Net loss		(16,383	)		(11,899	)
Preferred stock dividends		(1,725	)		—


Loss applicable to common shareholders	$	(18,108	)	$	(11,899	)


Loss per share:
Basic	$	(0.33	)	$	(0.26	)
Diluted	$	(0.33	)	$	(0.26	)

Weighted average shares outstanding, basic		55,341			45,945
Weighted average shares outstanding, diluted		55,341			45,945


	Three months ended March 31,
	2013		2012
Production
Crude oil (MBbls)		599		549
NGLs (MBbls)		234		215
Natural gas (MMcf)		3,565		6,294
Total crude oil, NGL and natural gas production (MBOE)		1,427		1,812

Prices
Crude oil ($ per Bbl)	$	105.28	$	107.05
NGLs ($ per Bbl)	$	30.45	$	42.24
Natural gas ($ per Mcf)	$	3.38	$	2.37

Prices - Adjusted for derivative settlements
Crude oil ($ per Bbl)	$	109.97	$	106.85
NGLs ($ per Bbl)	$	30.45	$	42.24
Natural gas ($ per Mcf)	$	3.59	$	3.65

(a)

Includes liability-classified share-based compensation expense attributable to our performance-based restricted stock units which are payable in cash upon the achievement of certain market-based performance metrics. A total less than $0.1 million and $0.1 million attributable to these awards is included in the three months ended March 31, 2013 and 2012.

(b)

Our equity-classified share-based compensation expense includes non-cash charges for our stock option expense and the amortization of common, deferred and restricted stock, and restricted stock unit awards related to equity-classified employee and director compensation in accordance with accounting guidance for share-based payments.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)


	As of
	March 31, 2013		December 31, 2012
Assets
Current assets	$	88,661	$	96,515
Net property and equipment		1,760,240		1,723,359
Other assets		20,900		23,115

Total assets	$	1,869,801	$	1,842,989


Liabilities and shareholders’ equity
Current liabilities	$	127,079	$	112,025
Revolving credit facility		38,000		—
Senior notes due 2016		295,080		294,759
Senior notes due 2019		300,000		300,000
Other liabilities and deferred income taxes		231,949		241,089
Total shareholders’ equity		877,693		895,116

Total liabilities and shareholders’ equity	$	1,869,801	$	1,842,989

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)


	Three months ended March 31,
	2013			2012
Cash flows from operating activities
Net loss	$	(16,383	)	$	(11,899	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		51,576			50,817
Derivative contracts:
Net losses		7,761			305
Cash settlements		3,557			7,981
Deferred income tax benefit		(8,789	)		(6,601	)
Loss (gain) on sales of assets, net		549			(756	)
Non-cash exploration expense		5,262			8,171
Non-cash interest expense		946			1,015
Share-based compensation (equity-classified)		1,085			1,615
Other, net		288			56
Changes in operating assets and liabilities		(237	)		19,997

Net cash provided by operating activities		45,615			70,701

Cash flows from investing activities
Capital expenditures - property and equipment		(85,973	)		(94,469	)
Proceeds from sales of assets, net		878			778

Net cash used in investing activities		(85,095	)		(93,691	)

Cash flows from financing activities
Proceeds from revolving credit facility borrowings		38,000			23,000
Repayment of revolving credit facility borrowings		—			(3,000	)
Dividends paid on preferred and common stock		(1,687	)		(2,586	)
Other, net		(61	)		—

Net cash provided by financing activities		36,252			17,414

Net decrease in cash and cash equivalents		(3,228	)		(5,576	)
Cash and cash equivalents - beginning of period		17,650			7,512

Cash and cash equivalents - end of period	$	14,422		$	1,936


Supplemental disclosures of cash paid for:
Interest (net of amounts capitalized)	$	340		$	557
Income taxes (net of refunds received)	$	—		$	(301	)

PENN VIRGINIA CORPORATION

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)


	Three months ended March 31,
	2013			2012
Reconciliation of GAAP “Loss attributable to common shareholders”
Non-GAAP “Loss, as adjusted, attributable to common shareholders”
Loss applicable to common shareholders	$	(18,108	)	$	(11,899	)
Adjustments for derivatives:
Net losses		7,761			305
Cash settlements		3,557			7,981
Adjustment for loss (gain) on sale of assets, net		549			(756	)
Impact of adjustments on income taxes		(4,143	)		(2,687	)

Loss, as adjusted, attributable to common shareholders (a)	$	(10,384	)	$	(7,056	)


Net loss, as adjusted, per share, diluted	$	(0.19	)	$	(0.15	)


Reconciliation of GAAP “Net loss” to Non-GAAP “Adjusted EBITDAX”
Net loss	$	(16,383	)	$	(11,899	)
Income tax benefit		(8,789	)		(6,601	)
Interest expense		14,479			14,774
Depreciation, depletion and amortization		51,576			50,817
Exploration		6,295			7,998
Share-based compensation expense (equity-classified awards)		1,085			1,615

EBITDAX		48,263			56,704
Adjustments for derivatives:
Net losses		7,761			305
Cash settlements		3,557			7,981
Adjustment for loss (gain) on sale of assets, net		549			(756	)
Adjustment for other non-cash items		207			—

Adjusted EBITDAX (b)	$	60,337		$	64,234

(a)

Net loss, as adjusted, represents the net loss adjusted to exclude the effects of non-cash changes in the fair value of derivatives, restructuring costs and net gains and losses on the sale of assets. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net loss, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net loss.

(b)

Adjusted EBITDAX represents net loss before income tax expense or benefit, interest expense, depreciation, depletion and amortization expense, exploration expense, and share-based compensation expense, further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, net gains and losses on the sale of assets and other non-cash items. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net loss. Adjusted EBITDAX represents EBITDAX as defined in our revolving credit facility.

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.


	First Quarter 2013			Full-Year 2013 Guidance
Production:
Crude oil (MBbls)		599			3,600		-	4,000
NGLs (MBbls)		234			825		-	925
Natural gas (MMcf)		3,565			13,400		-	14,200
Equivalent production (MBOE)		1,427			6,658		-	7,292
Equivalent daily production (BOEPD)		15,857			18,242		-	19,977
Percent crude oil and NGLs		58.4	%		64.5	%	-	69.4	%

Production revenues (a):
Crude oil	$	63.1			340.0		-	385.0
NGLs	$	7.1			24.0		-	27.0
Natural gas	$	12.0			50.0		-	57.0
Total product revenues	$	82.2			414.0		-	469.0
Total product revenues ($ per BOE)	$	57.61			62.18		-	64.32
Percent crude oil and NGLs		85.4	%		86.2	%	-	89.3	%

Operating expenses:
Lease operating ($ per BOE)	$	5.47			5.60		-	6.00
Gathering, processing and transportation costs ($ per BOE)	$	2.51			1.60		-	1.80
Production and ad valorem taxes (percent of oil and gas revenues)		7.2	%		6.8	%	-	7.2	%

General and administrative:
Recurring general and administrative	$	9.9			41.5		-	43.3
Share-based compensation	$	1.1			4.0		-	4.5
Restructuring	$	—			2.5		-	2.7
Total reported G&A	$	10.9			48.0		-	50.5

Exploration:
Total reported exploration	$	6.3			47.0		-	51.0
Unproved property amortization	$	5.3			43.0		-	45.0

Depreciation, depletion and amortization ($ per BOE)	$	36.14			36.00		-	39.00

Adjusted EBITDAX (b)	$	60.3			302.7		-	362.5

Capital expenditures:
Drilling and completion	$	86.5			400.0		-	450.0
Pipeline, gathering, facilities	$	3.0			18.0		-	20.0
Seismic (c)	$	1.0			4.0		-	5.0
Lease acquisitions, field projects and other	$	5.0			23.0		-	30.0
Total oil and gas capital expenditures	$	95.5			445.0		-	505.0

End of period debt outstanding	$	633.1
Effective interest rate		9.7	%
Income tax benefit rate		34.9	%		36.0	%	-	36.5	%

(a)	Assumes average benchmark prices of $91.12 per barrel for crude oil and $3.97 per MMBtu for natural gas, prior to any premium or discount for quality, basin differentials, the impact of hedges and other adjustments. NGL realized pricing is assumed to be $29.13 per barrel.

(b)	Adjusted EBITDAX is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

(c)	Seismic expenditures are also reported as a component of exploration expense and as a component of net cash provided by operating activities.

PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited - (continued)

Note to Guidance Table:

The following table shows our current derivative positions.


						Weighted Average Price
	Instrument Type			Average Volume Per Day		Floor/ Swap		Ceiling
Natural gas:				(MMBtu)		($ / MMBtu)
Second quarter 2013		Collars			10,000		3.50		4.30
Third quarter 2013		Collars			10,000		3.50		4.30
Fourth quarter 2013		Collars			15,000		3.67		4.37
First quarter 2014		Collars			5,000		4.00		4.50
Second quarter 2013		Swaps			15,000		3.92
Third quarter 2013		Swaps			15,000		3.92
Fourth quarter 2013		Swaps			10,000		4.04
First quarter 2014		Swaps			5,000		4.05
Second quarter 2014		Swaps			10,000		4.03
Third quarter 2014		Swaps			10,000		4.03

Crude oil:				(barrels)		($ / barrel)
Second quarter 2013		Collars			1,900		90.00		99.17
Third quarter 2013		Collars			1,900		90.00		99.17
Fourth quarter 2013		Collars			1,900		90.00		99.17
Second quarter 2013		Swaps			5,091		98.41
Third quarter 2013		Swaps			6,000		95.77
Fourth quarter 2013		Swaps			6,000		95.77
First quarter 2014		Swaps			6,000		93.60
Second quarter 2014		Swaps			6,000		93.60
Third quarter 2014		Swaps			5,500		92.91
Fourth quarter 2014		Swaps			5,500		92.91
First quarter 2014		Swaption	(a)		812		100.00
Second quarter 2014		Swaption	(a)		812		100.00
Third quarter 2014		Swaption	(a)		812		100.00
Fourth quarter 2014		Swaption	(a)		812		100.00
First quarter 2014		Swaption	(b)		1,000		100.00
Second quarter 2014		Swaption	(b)		1,000		100.00
Third quarter 2014		Swaption	(b)		1,000		100.00
Fourth quarter 2014		Swaption	(b)		1,000		100.00

(a)

This written swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for calendar year 2014 is higher than or equal to $100.00 per barrel on December 31, 2013, the counterparty will exercise its option to enter into a fixed price swap at $100.00 per barrel for calendar year 2014, at which point the contract functions as a fixed price swap. If the forward commodity price for calendar year 2014 is lower than $100.00 per barrel on December 31, 2013, the option expires and no fixed price swap is in effect.

(b)	The option exercise date on these swaptions for calendar year 2014 is June 28, 2013.

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 $10.3 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 $32.1 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.

Ranger Oil (ROCC) 8-KResults of Operations and Financial Condition