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

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 YEAR-END 2013 PROVED RESERVES

AND PROVIDES OPERATIONAL UPDATE

CONTINUED EXCELLENT DRILLING RESULTS IN THE EAGLE FORD SHALE

EAGLE FORD SHALE PROVED RESERVES INCREASED BY 189 PERCENT TO 55 PERCENT OF TOTAL PROVED RESERVES

PROVED OIL RESERVES INCREASED BY 144 PERCENT TO 45 PERCENT OF TOTAL PROVED RESERVES

OIL / NGLS WERE 68 PERCENT OF PRODUCTION AND 90 PERCENT OF PRODUCT REVENUES IN THE FOURTH QUARTER OF 2013

EAGLE FORD SHALE POSITION EXPANDED BY 19 PERCENT TO APPROXIMATELY 80,000 NET ACRES

DRILLING INVENTORY INCREASED BY 26 PERCENT TO APPROXIMATELY 1,125 LOCATIONS

RADNOR, PA (Globe Newswire) February 19, 2014 –Penn Virginia Corporation (NYSE: PVA) today announced year-end 2013 proved oil and gas reserves and provided an update of its operations, including full-year and fourth quarter 2013 results.

Year-End 2013 Proved Reserves Highlights

Highlights of year-end 2013 proved reserves, as compared to year-end 2012, were as follows:

• Proved oil and gas reserves increased by 22.9 MMBOE, or 20 percent, to 136.3 million barrels of oil equivalent (MMBOE) from 113.5 MMBOE.

• Eagle Ford Shale reserves increased by 189 percent to 75.6 MMBOE (89 percent oil and NGLs), or 55 percent of the total.

• Oil reserves increased 144 percent to 60.7 million barrels (MMBbls), or 45 percent of the total from 24.9 MMBbls, or 22 percent of the total.

• Natural gas liquids (NGLs) reserves increased six percent to 22.0 MMBbls, or 16 percent of the total from 20.7 MMBbls, or 18 percent of the total.

• Natural gas reserves decreased by 85.4 billion cubic feet (Bcf) (14.2 MMBOE), or 21 percent, to 322.1 Bcf (53.7 MMBOE), or 39 percent of the total.

• The pre-tax present value of estimated future net cash flows from proved reserves, discounted at 10 percent (PV-10) and assuming an oil price of $96.78 per barrel and a natural gas price of $3.67 per MMBtu (million British thermal units), was $1,717 million, an increase of 148 percent from $692 million.

• The PV-10 value of Eagle Ford Shale proved reserves was $1,584 million (PV-10 value of proved developed reserves in the Eagle Ford Shale was $826 million), a 163 percent increase from $603 million.

• The PV-10 value of proved developed reserves was $963 million, a 53 percent increase from $628 million.

Fourth Quarter 2013 and Recent Operational Highlights

Fourth quarter 2013 operational results and other operational highlights were as follows:

• Fourth quarter production was 1.8 MMBOE, or 20,020 barrels of oil equivalent (BOE) per day (BOEPD), up two percent compared to 1.8 MMBOE, or 19,638 BOEPD, in the third quarter of 2013.

• Fourth quarter Eagle Ford Shale production was 13,111 BOEPD, up five percent compared to 12,489 BOEPD in the third quarter.

• Quarterly oil production was a record 11,130 barrels of oil per day (BOPD), an increase of seven percent over 10,373 BOPD in the third quarter.

• In the Eagle Ford Shale, we have a total of 179 (116.7 net) producing wells, 13 (10.1 net) operated wells completing or waiting on completion, two (0.9 net) outside operated wells being completed, six (4.2 net) operated wells being drilled and no outside operated wells being drilled.

• The average peak gross production rate per well for the 23 (12.3 net) most recent operated wells since our last quarterly report was 1,582 BOEPD, with oil representing an average of 86 percent of wellhead volumes. The initial 30-day average gross production rate for the 19 of these 23 wells with a30-day production history was 1,076 BOEPD, with oil representing an average of 85 percent of wellhead volumes. The average lateral length for these 23 operated wells was 5,722 feet, with an average of 24.3 frac stages.

• The average total drilling and completion cost per frac stage was approximately $380,000 in the fourth quarter of 2013, as compared to approximately $390,000 in the third quarter of 2013. Even with the reduction in costs, we used approximately 16 percent more proppant per stage in the fourth quarter of 2013 as compared to the third quarter and achieved correspondingly better production results per frac stage.

• During the fourth quarter of 2013, the average peak gross production rate per frac stage was 67.0 BOEPD and the 30-day average gross production rate per frac stage was 45.2 BOEPD, increases of 18 percent and 19 percent as compared to averages of 57.0 BOEPD and 37.8 BOEPD in the third quarter.

• Currently, we have a total of approximately 118,000 gross (80,000 net) acres in the Eagle Ford Shale.

• Approximately 12,500 net acres, or 19 percent, have been added in the Eagle Ford Shale since our last quarterly report at an average cost of approximately $2,800 per acre and we continue to aggressively acquire acreage in our “backyard.”

• We estimate that we currently have approximately 1,125 undeveloped drilling locations, which is a drilling inventory of over 10 years, assuming our ongoing drilling program.

• This inventory increased approximately 26 percent from approximately 890 locations reported previously.

• 22 of our most recently drilled wells were drilled off of 10 multi-well pads, with an average effective nominal spacing of approximately 60 acres.

Eagle Ford Shale Operational Update

Net production from the Eagle Ford Shale was 13,111 BOEPD in the fourth quarter, an increase of five percent from 12,489 BOEPD in the third quarter. Crude oil production alone in the Eagle Ford Shale during the fourth quarter was 10,574 BOPD, or 81 percent of total Eagle Ford Shale production. During the fourth quarter, we completed 19 (9.6 net) operated wells and participated in the completion of three (1.4 net) outside operated wells. In the Eagle Ford Shale, we have a total of 179 (116.7 net) producing wells, 13 (10.1 net) operated wells completing or waiting on completion, two (0.9 net) outside operated wells being completed, six (4.2 net) operated wells being drilled and no outside operated wells being drilled.

Currently, we are drilling with six operated rigs and no outside-operated rigs. During the second half of 2013, both of the outside-operated rigs were released. Our capital program for 2014 is based on drilling with six operated rigs all year, along with a small number of non-operated wells that we expect will be proposed by partners.

In the third quarter of 2013, we discussed our plans to drill a two-well pad, one well of which was to be drilled in the lower Eagle Ford Shale and the second of which was to be drilled in the upper Eagle Ford Shale. The purpose of this two-well pad was to test the potential of the upper Eagle Ford Shale and to determine if it was a separate reservoir from the lower Eagle Ford Shale, which has been the reservoir we have drilled to and completed in to date. If the test is successful, a significant number of drilling locations would be added to our drilling inventory. As of this date, the lower Eagle Ford Shale well has been drilled and the upper Eagle Ford Shale well is currently being drilled in its lateral. Completion of both wells is expected late in the first quarter or early in the second quarter of 2014.

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

					Peak Gross Daily Production Rates(1)						30-Day Average Gross Daily Production Rates(1)
Well Name	Lateral Length		Frac Stages		Oil Rate		Equivalent Rate		Equivalent Rate per Frac Stage		Oil Rate		Equivalent Rate		Equivalent Rate per Frac Stage
	Feet				BOPD		BOEPD		BOEPD/stage		BOPD		BOEPD		BOEPD/stage
Operated wells
Bongo Hunter #1H		6,258		26		2,196		2,280		87.7		1,347		1,421		54.6
Bongo North #1H		8,026		33		1,072		1,156		35.0		868		962		29.2
Bongo North #2H		7,922		33		1,315		1,414		42.9		1,112		1,220		37.0
Pilsner Hunter #2H		7,138		30		1,125		1,448		48.3		908		1,219		40.6
Pilsner Hunter #3H		5,260		22		1,153		1,384		62.9		853		1,030		46.8
Pilsner Hunter #4H		6,518		28		1,571		1,841		65.8		942		1,137		40.6
Pilsner Hunter #5H		7,462		32		1,563		1,937		60.5		1,188		1,476		46.1
Rhino Hunter #6H		3,665		16		1,574		1,744		109.0		953		1,064		66.5
Rhino Hunter #7H		4,500		20		1,577		1,780		89.0		1,163		1,305		65.2
Effenberger #4H		5,019		22		702		750		34.1		580		685		31.2
Effenberger #5H		3,784		17		1,349		1,532		90.1		744		864		50.8
RCR Hinton #1H		5,414		23		1,460		1,712		74.4		851		994		43.2
RCR Hinton #2H		4,331		19		1,490		1,730		91.1		624		760		40.0
RCR Hinton #3H		4,972		15		994		1,133		75.5		766		893		59.5
Hill Unit #1H		4,833		21		308		330		15.7		233		252		12.0
Hill Unit #2H		4,800		20		341		366		18.3		299		322		16.1
Blonde Unit #1H		5,683		26		2,125		2,521		97.0		1,506		1,844		70.9
Kosmo Unit #1H		5,745		24		1,673		2,168		90.3		925		1,217		50.7
Porter Unit #1H		7,163		31		2,045		2,670		86.1		1,332		1,781		57.5
Pavlicek #2H		5,394		24		1,057		1,319		55.0		—		—		—
Pavlicek #5H		4,496		20		1,112		1,411		70.6		—		—		—
Zebra Hunter #2H		6,697		29		1,301		1,511		52.1		—		—		—
Zebra Hunter #3H		6,518		28		2,001		2,250		80.4		—		—		—
Averages (23 most recent operated wells)		5,722		24.3		1,352		1,582		66.6		905		1,076		45.2
Outside operated wells
Dorothy Springs B#2H (Hunt)		6,629		22		248		264		12.0		233		251		11.4
O. Borchers C#1H (Hunt)		9,728		32		223		242		7.6		223		236		7.4
Cinco Ranch E#5H (Hunt)		8,580		30		407		424		14.1		218		227		7.6
O. Borchers E#1H (Hunt)		6,448		20		295		311		15.6		185		197		9.8

⁽¹⁾  Wellhead rates only; the natural gas associated with these wells is yielding between 145 and 165 barrels of NGLs per million cubic feet.

Of our 23 most recent operated wells, 22 were drilled on 10 pads, with an average effective nominal spacing of approximately 60 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 1,125 well drilling inventory.

Fourth Quarter 2013 Operational Results

Production

	Total and Daily Equivalent Production for the Three Months Ended
Region / Play Type	Dec. 31, 2013		Sept. 30, 2013		Dec. 31, 2012		Dec. 31, 2013		Sept. 30, 2013		Dec. 31, 2012
	(in MBOE)						(in BOEPD)
Texas		1,447		1,395		944		15,734		15,164		10,265
Eagle Ford Shale		1,206		1,149		632		13,111		12,489		6,872
East Texas		241		246		312		2,622		2,674		3,393
Mid-Continent		204		219		266		2,213		2,385		2,892
Mississippi		181		179		203		1,969		1,951		2,209
Other(2)		10		13		8		104		138		78
Totals		1,842		1,807		1,421		20,020		19,638		15,444

⁽²⁾  Other includes Marcellus Shale (since 2012) and Pearsall Shale (since 2013) production.

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

Production in the fourth quarter of 2013 was in line with the midpoint of previously provided guidance. As shown in the table above, production in the fourth quarter of 2013 was 1.8 MMBOE, or 20,020 BOEPD, compared to 1.8 MMBOE, or 19,638 BOEPD, in the third quarter of 2013. As a percentage of total equivalent production, oil and NGL volumes were 68 percent in the fourth quarter of 2013, compared to 67 percent in the third quarter of 2013.

Proved Reserves

As set forth in the table below, proved reserves were 136.3 MMBOE at year-end 2013, as compared to 113.5 MMBOE at year-end 2012. The 20 percent increase in proved reserves was due primarily to a 53.7 MMBOE, or 189 percent, increase in Eagle Ford Shale proved reserves from 26.1 MMBOE at year-end 2012 to 75.6 MMBOE at year-end 2013, partially offset by downward reserve revisions, much of which is natural gas, as a result of eliminating some significant natural gas proved undeveloped (PUD) reserves due to the five-year rule of the Securities and Exchange Commission (SEC).

	Proved Reserves at December 31, 2013(3)
	Total Oil Equivalent Reserves (MMBOE)			Oil and Condensate Reserves (MMBbls)			NGLs Reserves (MMBbls)			Natural Gas Reserves (Bcf)
Proved reserves at December 31, 2012		113.5			24.9			20.7			407.5
2013 production		(6.8	)		(3.4	)		(1.0	)		(14.4	)
2013 extensions, discoveries and other additions		46.6			34.1			6.5			36.3
2013 revisions		(28.4	)		(4.4	)		(5.3	)		(111.9	)
2013 purchases (sales) of reserves in place, net		11.4			9.6			1.0			4.7
Proved reserves at December 31, 2013		136.3			60.7			21.9			322.1
Percentage of equivalent reserves		100.0	%		44.5	%		16.1	%		39.4	%
Proved developed reserves at December 31, 2012		47.0			10.5			8.3			169.4
Percentage of proved reserves		41.4	%		42.1	%		39.9	%		41.6	%
Proved developed reserves at December 31, 2013		55.0			19.3			8.5			163.2
Percentage of proved reserves		40.4	%		31.8	%		38.9	%		50.7	%
Present value of future net cash flows before income taxes ($mil.)(3)	$	1,716.6

⁽³⁾  The estimated reserves and present value were based on pricing assumptions for Henry Hub natural gas of $3.67 per MMBtu and West Texas Intermediate crude oil of $96.78 per barrel. These compare to prices of $2.76 per MMBtu and $94.71 per barrel, respectively, at December 31, 2012. Both prices exclude the effects of hedged production. One barrel of oil or NGLs is assumed to be equivalent to six Mcf of natural gas. MMBbls equals millions of barrels of liquids.

Note - Numbers may not add due to rounding.

The PV-10 value of the proved reserves at year-end 2013 was approximately $1,717 million (see statement regarding non-GAAP measures below). This PV-10 value was based on a Henry Hub price of $3.67 per MMBtu for natural gas and a West Texas Intermediate (WTI) price of $96.78 per barrel for oil, each of which represents the unweighted arithmetic average of the first-day-of-the-month prices during the 12-month period ending on December 31, 2013.

The estimated year-end 2013 proved reserves included proved developed reserves of 55.0 MMBOE, with a PV-10 value of $963 million, and PUD reserves of 81.3 MMBOE, with a PV-10 value of $754 million. During 2013, we added 47 MMBOE of proved reserves from extensions, discoveries, purchases and other additions in the Eagle Ford Shale play.

Because we will not be able to develop a portion of our PUD reserves within the five-year time period required under the reserve rules of the SEC, we had approximately 25 MMBOE of negative revisions, in the Haynesville Shale, Cotton Valley, Selma Chalk, Granite Wash and Marcellus Shale plays.

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 the year ended December 31, 2013 is not yet available. The standardized measure will be provided in our forthcoming Form 10-K for the year ended December 31, 2013 to be filed with the SEC.

Fourth Quarter and Full-Year 2013 Conference Call

A conference call and webcast, during which management will discuss fourth quarter 2013 financial and operational results, is scheduled for Thursday, February 20, 2014 at 10:00 a.m. ET. Prepared remarks by H. Baird Whitehead, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing toll free 1-877-316-5288 (international: 1-734-385-4977) five to 10 minutes before the scheduled start of the conference call (use the conference code 23232008), 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 23232008. 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 Texas, and other properties in 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: 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 oil and 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.

Contact:	James W. Dean
	Vice President, Corporate Development
	Ph: (610) 687-7531 Fax: (610) 687-3688
	E-Mail:invest@pennvirginia.com