8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report: April 3, 2013 (April 3, 2013)

(Date of Earliest Event Reported)

PENN VIRGINIA CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Virginia	1-13283	23-1184320
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)

Four Radnor Corporate Center, Suite 200 100 Matsonford Road, Radnor, Pennsylvania	19087
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code: (610) 687-8900

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01. Regulation FD Disclosure.

Exhibit 99.1 to this Current Report sets forth certain information regarding Penn Virginia Corporation (“PVA”) and the properties to be acquired in our wholly-owned subsidiary Penn Virginia Oil & Gas Corporation’s acquisition of Eagle Ford Hunter, Inc. (the “Acquisition”).

Exhibit 99.2 to this Current Report sets forth certain historical financial statements of Eagle Ford Hunter, Inc.

On Wednesday, April 3, 2013, PVA is hosting a telephone conference and webcast during which H. Baird Whitehead, PVA’s President and Chief Executive Officer, and other members of PVA’s management will discuss the Acquisition. A copy of the presentation materials to be used in connection with the telephone conference and webcast is furnished and attached as Exhibit 99.3 hereto and is incorporated by reference herein. The presentation materials will be posted under “Presentations & Webcasts” in the “Investor Relations” section of our website prior to the telephone conference and webcast.

In accordance with General Instruction B.2 of Form 8-K, the information presented herein under Item 7.01 and set forth in the attached Exhibit 99.1, Exhibit 99.2 and Exhibit 99.3 shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), or otherwise subject to the liability of that section, and is not to be incorporated by reference into any filing of PVA under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits.

99.1	Information Regarding Penn Virginia Corporation and the Acquisition Properties.
99.2	Historical Financial Statements of Eagle Ford Hunter, Inc.
99.3	Presentation Materials.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Date: April 3, 2013

Penn Virginia Corporation
By:	/s/ Nancy M. Snyder
Name:	Nancy M. Snyder
Title:	Executive Vice President, Chief Administrative Officer, General Counsel and Corporate Secretary

Exhibit Index

Exhibit No.	Description
99.1	Information Regarding Penn Virginia Corporation and the Acquisition Properties.
99.2	Historical Financial Statements of Eagle Ford Hunter, Inc.
99.3	Presentation Materials.

EX-99.1

Exhibit 99.1

INFORMATION REGARDING PENN VIRGINIA CORPORATION

AND THE ACQUISITION PROPERTIES

This Exhibit 99.1 sets forth certain information regarding PVA and the properties to be acquired in connection with the Acquisition.

Our current focus is on drilling unconventional horizontal development wells in shale formations principally in the Eagle Ford Shale play in South Texas, where we are the operator on 42,430 gross (35,020 net) acres located primarily in Lavaca and Gonzalez Counties. Since 2010, we have drilled and completed 70 gross (58.9 net) wells in the Eagle Ford Shale play. We also have 8,045 net acres in the horizontal Granite Wash play in the Mid-Continent region and pursue select drilling opportunities in the play through participation in wells drilled by our joint venture partner.

During the quarter ended December 31, 2012, our average daily production rate was 15,444 BOEPD, which was 39% oil, 17% NGLs and 44% natural gas. As we continue to develop our Eagle Ford Shale assets, we expect oil, and to a lesser extent NGLs, to comprise a greater percentage of our daily production.

The following table sets forth by region our proved reserves and reserves to production ratio as of December 31, 2012, as well as our average daily production for the quarter ended December 31, 2012:

	As of December 31, 2012										Quarter ended December 31, 2012
Region	Proved reserves (MMBOE)(1)		% Total proved reserves			% Proved developed			Reserves to production ratio (in years)(2)		Average daily production (BOEPD)
Texas		82.9		73.0	%		33.2	%		22.1		10,265
Mid-Continent		12.5		11.0	%		79.2	%		11.8		2,892
Mississippi		17.6		15.5	%		53.8	%		21.8		2,209
Appalachia		0.5		0.5	%		22.6	%		17.6		78
Total		113.5		100.0	%		41.4	%		20.1		15,444

(1) Based on an equivalent ratio of one barrel of oil and NGLs to six Mcf of natural gas.

(2) Reserves to production ratio is determined by dividing our proved reserves by the average daily production attributable to such reserves for the quarter ended December 31, 2012, on an annualized basis.

We believe our pending acquisition, or the Acquisition, of Eagle Ford Hunter, Inc., or Eagle Hunter, represents both a strategic and transformative acquisition for us. Eagle Hunter owns 40,565 gross (19,037 net) acres of producing oil, NGL and natural gas properties, which are located in Gonzales and Lavaca Counties, Texas and are largely contiguous to our current leaseholds. Eagle Hunter’s average daily production for the month of February 2013 was 3,173 BOEPD, of which 90% was oil. As of March 31, 2013, there were 46 gross (22.1 net) producing wells and seven gross wells awaiting completion.

For the year ended December 31, 2012, the Eagle Hunter assets had revenues of $72.1 million and direct operating expenses of $10.3 million. As of December 31, 2012, proved reserves associated with the Eagle Hunter assets were approximately 12.0 MMBOE, of which 37% were proved developed reserves and 96% were oil and NGLs. Included in the proved reserve estimates were 44 gross proved developed wells and 51 gross proved undeveloped locations. During the quarter ended December 31, 2012, the average daily production rate was 2,710 BOEPD, which was 89% oil, 6% NGLs and 5% natural gas.

The following table sets forth information relating to Eagle Hunter’s proved reserves as of December 31, 2012:

	As of December 31, 2012(1)
Category	Oil (MMBbl)		NGLs (MMBbl)		Natural  Gas (Bcf)		Oil  Equivalents (MMBOE)		PV-10 ($  million)(2)
Proved Developed		3.9		0.3		1.1		4.4	$	156.0
Proved Undeveloped		6.9		0.4		1.8		7.6		84.7
Total Proved Reserves		10.8		0.7		2.9		12.0	$	240.7

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(1) Estimated proved reserve data for the Eagle Hunter assets was prepared by Cawley, Gillespie & Associates, Inc., or Cawley Gillespie, using unweighted average first-day-of-the month prices for the year ended December 31, 2012. The average prices for oil, NGLs and natural gas were $98.77 per barrel of oil, $43.57 per barrel of NGLs and $2.88 per Mcf of natural gas, respectively.

(2) A reconciliation of Eagle Hunter’s PV-10 to standardized measure, assuming that Eagle Hunter’s tax rates would be the same as ours, is as follows:

	($ in millions)
PV-10 value	$	240.7
Income tax effect		(67.7	)
Standardized measure	$	173.0

PV-10 is the present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to financial hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Standardized measure is the present value of estimated future cash inflows from proved natural gas and oil reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as are used to calculate PV-10. Standardized measure differs from PV-10 because standardized measure includes the effect of future income taxes.

PV-10 is considered a non-GAAP measure. We believe the presentation of the PV-10 value is relevant and useful to our investors because it presents the discounted future net cash flows attributable to our proved reserves before taking into account corporate income taxes. We believe investors and creditors utilize our PV-10 value as a basis for comparison of the relative size and value of our reserves to other companies. Neither PV-10 value nor standardized measure reflects the impact of financial hedging transactions.

Following the consummation of the Acquisition, we will have a larger consolidated position of approximately 83,000 gross (54,000 net) acres in the Eagle Ford Shale play. We plan to operate four rigs on the operated portion of our leaseholds, and we believe that Eagle Hunter’s operating partner plans to continue a two-rig program. As of March 31, 2013, we would have had an interest in 117 gross (82.0 net) producing wells and up to an estimated 640 additional gross (420 net) drilling locations. This new combined acreage position will afford us a multi-year inventory of identified locations in an area familiar to us and where we have experience and institutional knowledge of the geology, reservoir characteristics and current industry best practices in drilling and completion techniques. Further, we believe that the Acquisition will enable us to leverage our increased scale and reduce our operating costs and development capital expenditures per well. We anticipate spending approximately $385 million on drilling and completions in 2013 and anticipate bringing a total of 62 gross (39.3 net) wells online by year-end.

After giving effect to the Acquisition, on a pro forma basis, our proved reserves as of December 31, 2012 would have been approximately 125.5 MMBOE, of which 41% would have been proved developed reserves and 46% would have been oil and NGLs. Our Eagle Ford Shale proved reserves would have been approximately 38.2 MMBOE, which would have comprised 30% of our total proved reserves. The pro forma PV-10 value of our proved reserves as of December 31, 2012 would have been $933.2 million. Our pro forma average daily production rate for the quarter ended December 31, 2012 would have been 18,154 BOEPD, consisting of 47% oil, 15% NGLs and 38% natural gas. PV-10 is considered a non-GAAP measure. A reconciliation of our pro forma PV-10 to standardized measure, assuming that Eagle Hunter’s tax rates would be the same as ours, is as follows:

	($ in thousands)
PV-10 value	$	933,209
Income tax effect		(262,250	)
Standardized measure	$	670,959

Description of Properties

Pro Forma Overview of Properties

The following map shows our asset base, on a pro forma basis, after giving effect to the Acquisition. For a further description of our historical activity in each of these regions, please see the information that follows this map.

(1) Excludes 742 MBoe related to assets divested in 2012.

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Eagle Ford Shale

We are active in the Eagle Ford Shale play in South Texas and our current leaseholds are located primarily in Gonzales and Lavaca Counties. We own and operate a total of 42,430 gross (35,020 net) acres in the Eagle Ford Shale. Our Eagle Ford Shale oil and NGL reserves comprise approximately 21% of our total equivalent proved reserves as of December 31, 2012. In addition, according to Wright & Company Inc., our independent third-party reserve engineers, the average gross estimated ultimate recovery for our Eagle Ford Shale proved undeveloped locations with full-length laterals in Gonzales County and Lavaca County is approximately 400 MBOE and 500 MBOE, respectively.

During 2012, we invested approximately $350 million, or more than 90% of our 2012 capital program, to projects in the Eagle Ford Shale and drilled a total of 35 gross (29.5 net) wells, all but one of which was successful. We believe our project inventory in the Eagle Ford Shale provides us opportunities for continued oil and NGL-focused development over the next several years. Since December 2012, we have completed seven gross (6.5 net) Eagle Ford Shale wells, bringing our total to date to 71 gross (59.9 net) producing wells, with four gross wells being drilled and three gross wells awaiting completion. The initial 30-day average gross wellhead production rate for 68 of these wells with a 30-day production history was approximately 620 BOEPD. Our Eagle Ford Shale production was 6,872 BOEPD during the quarter ended December 31, 2012, comprised of approximately 80% oil, 11% NGLs and 9% natural gas. Our daily production from the Eagle Ford Shale for February 2013 was 7,776 BOEPD.

Mid-Continent

Our Mid-Continent efforts are focused on drilling the horizontal Granite Wash play where we have approximately 55,000 net leasehold acres across Washita, Custer, Blaine, Dewey, Caddo, Comanche, Grady and Jefferson Counties, Oklahoma and Roberts County, Texas. The Mid-Continent region contains primarily liquids-rich natural gas reserves, and represents approximately 11% of our total equivalent proved reserves as of December 31, 2012. Our Mid-Continent production was 2,892 BOEPD during the quarter ended December 31, 2012.

Activity in this region is primarily conducted through participation in wells drilled by our joint venture partner. During 2012, we invested approximately $25 million, or 6% of our 2012 capital program, to projects in this region. In 2013, we plan to invest approximately $13 million to participate in five gross (2.2 net) wells.

East Texas

In East Texas, we have approximately 33,000 net leasehold acres located in Harrison, Panola and Marion Counties. Our Carthage field in East Texas, consisting of our Cotton Valley and Haynesville Shale properties, represents approximately 50% of our total equivalent proved reserves as of December 31, 2012. Our East Texas production was 3,393 BOEPD during the quarter ended December 31, 2012 and was 70% natural gas.

Mississippi

Our Mississippi assets are located primarily in the Selma Chalk play in Marion, Lamar, Forrest and Jefferson Davis Counties where we have approximately 30,000 net leasehold acres and represent approximately 16% of our total equivalent proved reserves as of December 31, 2012. Our Mississippi production was 2,209 BOEPD during the quarter ended December 31, 2012 and was substantially all natural gas.

Appalachia

In Appalachia, we have approximately 38,000 net leasehold acres located primarily in Potter and Tioga Counties, Pennsylvania. Our Appalachian assets consist of our Marcellus Shale properties and represent less than 1% of our total equivalent proved reserves as of December 31, 2012. Our Appalachian production was 78 BOEPD during the quarter ended December 31, 2012 and was substantially all natural gas.

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Other Recent Developments

Hedging Activity

Since December 31, 2012, we have entered into several derivative financial instruments. The following table sets forth our commodity derivative positions as of March 31, 2013.

	Instrument		Average Volume  Per Day			Weighted Average Price
						Floor/Swap			Ceiling
			(barrels)			($/barrel)
Crude Oil:
First quarter 2013		Collars		1,590		$	90.00		$	99.35
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
First quarter 2013		Swaps		2,906			102.72
Second quarter 2013		Swaps		3,750			101.26
Third quarter 2013		Swaps		4,000			98.43
Fourth quarter 2013		Swaps		4,000			98.43
First quarter 2014		Swaps		4,000			95.27
Second quarter 2014		Swaps		4,000			95.27
Third quarter 2014		Swaps		3,500			94.43
Fourth quarter 2014		Swaps		3,500			94.43
First quarter 2014		Swaption		1,812			100.00
Second quarter 2014		Swaption		1,812			100.00
Third quarter 2014		Swaption		1,812			100.00
Fourth quarter 2014		Swaption		1,812			100.00
Natural Gas:				(in MMBtu	)	($	/MMBtu	)
First quarter 2013		Collars		10,000		$	3.50		$	4.30
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
First quarter 2013		Swaps		10,000			4.01
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

Business Strengths

We believe that we are well positioned to successfully execute the key elements of our business strategies based on the following business strengths:

• Substantial block of leasehold acreage in the Eagle Ford Shale play. Upon the consummation of the Acquisition, we will own approximately 54,000 net leasehold acres in Gonzalez and Lavaca Counties, Texas, which are generally contiguous. Eagle Hunter currently has 46 gross producing wells, and we believe that the blocky nature of our post-Acquisition combined acreage will provide us up to approximately 80 additional drilling locations. We expect that the scale and concentration of our acreage, combined with our experience as operator, will also enable us to achieve operational efficiencies and improve our drilling and completion costs.

• Continued growth in oil-weighted production and reserves. For the quarter ended December 31, 2012, approximately 47% of our pro forma average daily production would have been oil, which would have represented approximately 79% of revenue from sales of oil, NGLs and natural gas on a pro forma basis for that period. We currently operate a three-rig program on our existing Eagle Ford Shale assets and expect to increase to a six-rig program following the Acquisition. Of these six, four will be operated by us. We plan to drill or participate in approximately 62 gross (39.3 net) wells in the Eagle Ford Shale play in 2013.

• High quality asset base that is geographically and geologically diverse. Our proved reserves, production and resource potential are located within multiple onshore U.S. basins that are well understood. These various basins provide exposure to a variety of reservoir formations with various compositions of oil, NGLs and natural gas. We believe this diversity in geography and commodity exposure mitigates our exposure to temporary price dislocations in any one market.

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• Active portfolio management. As production from the Eagle Ford Shale grows and comprises a greater portion of our total production, we will have the ability to monetize non-core assets, which we expect will provide us with cash to reinvest in our business and repay debt. This allows us to focus on a portfolio of core properties with significant potential to increase our proved reserves and production.

• Experienced management and technical teams. Our senior management team has an average of over 23 years of industry experience and is supported by technical and operating personnel who also have substantial industry experience and expertise. Since late 2010, we have drilled and completed 70 gross (58.9 net) wells in the Eagle Ford Shale play. As an active industry participant in the Eagle Ford Shale, we have acquired extensive experience and familiarity with our assets that we will be able to use to develop the Eagle Hunter assets.

Business Strategies

We intend to pursue the following business strategies:

• Continue to expand oil and NGL reserves and drilling inventory. Upon consummation of the Acquisition, we anticipate spending up to approximately $430 million to $485 million for capital expenditures in 2013, of which over 90% will be allocated to our Eagle Ford Shale acreage. Pro forma for the Acquisition, approximately 35% of our leasehold position will be held by production. We anticipate the remaining acreage can be held within three years with a five-rig development program.

• Grow our cash flows and margins. We expect our operating cash flows and margins will continue to grow, on a pro forma basis taking into consideration recent asset sales, as we increase our oil and NGL production through investment in higher rate-of-return development oil projects.

• Maintain our liquidity and financial position. We expect to continue to use our operating cash flows and borrowings under our Revolver to fund our capital requirements in 2013. Based on our capital expenditure plan for 2013 and the contribution to our cash flow and reserve value expected from the Eagle Hunter assets, we expect to fund our development plan through operating cash flow and undrawn capacity on our Revolver.

• Maximize long-term optionality across our portfolio. Our substantial Haynesville Shale and Cotton Valley Sands properties are largely held by production. Retaining these assets provides us the option to deploy capital on these leaseholds in a higher natural gas price environment. Given that these properties are past their initial production declines, we feel they will exhibit a more gradual decline in the future and, based on estimated reserves, have a long reserve to production life. We also continue to evaluate divestment opportunities with respect to our non-core assets with limited near-term development. We expect that any divestitures of these non-core assets will provide us with cash to reinvest in higher growth oil- and NGL-focused projects. Further, as production from our Eagle Ford acreage grows, we have the ability to monetize these assets to improve our overall operating cost profile and liquidity.

• Manage risk exposure through an active hedging program. We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected production. The level of our hedging activity and duration of the instruments employed depend upon our cash flows at risk, available hedge prices and our operating strategy. As of March 31, 2013, we have hedged approximately 69% of our estimated crude oil production at average floor/swap and ceiling prices of $96.67 and $99.73 per barrel, respectively, for 2013. In addition, as of March 31, 2013, we have hedged approximately 68% of our estimated natural gas production at a weighted-average floor/swap and ceiling prices of $3.77 per MMBtu and $4.13 per MMBtu, respectively, for 2013. Following the closing of the Acquisition, we expect to enter into additional hedges and target an overall hedged percentage resembling our current percent of expected production.

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The summary other financial data and key credit statistics presented as of and for the year ended December 31, 2012 are derived from our unaudited pro forma condensed consolidated financial statements. The pro forma financial data gives effect to the proposed acquisition and to the financing thereof with a combination of debt and the issuance to Magnum Hunter Resources Corporation of $40 million of our common stock. The unaudited pro forma financial data are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the proposed acquisition and other transactions listed above had been consummated on the dates indicated or of results that may be achieved in the future.

	Pro Forma		Historical
	Year Ended December 31,		Year Ended December 31,
	2012		2012		2011		2010
	(in thousands)
Other financial data and key credit statistics:
Ratio of earnings to fixed charges and preferred stock dividends(1)		—		—		—		—
EBITDAX(2)	$	194,652	$	132,823	$	84,053	$	137,653
Adjusted EBITDAX(2)		309,447		247,618		222,509		173,347
Total interest expense(3)		94,917		59,339		56,216		53,679
Ratio of total long-term debt to Adjusted EBITDAX(2)		3.3		2.4		3.1		2.9
Ratio of Adjusted EBITDAX to total interest expense(2)(3)		3.3		4.2		4.0		3.1

(1) For purposes of computing our ratio of earnings to fixed charges and preferred stock dividends on a consolidated basis, (x) earnings consist of the aggregate of income (before adjustment for income taxes, extraordinary items and income or loss from equity investees), plus fixed charges, amortization of capitalized interest and distributed income of equity investees, and minus capitalized interest, and (y) fixed charges consist of interest expense (including amounts capitalized), amortization of debt issuance costs, the portion of rental expense representing the interest factor and preferred stock dividends on a pre-tax basis. For the years ended December 31, 2012, 2011 and 2010, we had a deficiency of earnings to fixed charges of $176.9 million, $223.1 million and $109.6 million, respectively. The deficiency of earnings to fixed charges for the pro forma period is $239.2 million.

(2) Adjusted EBITDAX represents net loss before income tax benefit, interest expense, depreciation, depletion and amortization expenses, exploration expenses and share-based compensation expense (“EBITDAX”), further adjusted to exclude the effects of non-cash changes in the fair value of derivatives, loss on firm transportation commitment, impairments, net gains and losses on the sale of assets, loss on the extinguishment of debt 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 Revolver. The following table provides a reconciliation of net income to EBITDAX and to Adjusted EBITDAX:

	Pro Forma			Historical
	Year Ended December 31,			Year Ended December 31,
	2012			2012			2011			2010
	(in thousands)
Net loss from continuing operations	$	(141,244	)	$	(104,589	)	$	(132,915	)	$	(65,327	)
Add:
Income tax benefit		(92,734	)		(68,702	)		(88,155	)		(42,851	)
Interest expense		94,917			59,339			56,216			53,679
Depreciation, depletion and amortization expenses		232,263			206,336			162,534			134,700
Exploration expenses		95,103			34,092			78,943			49,641
Share-based compensation expense		6,347			6,347			7,430			7,811
EBITDAX	$	194,652		$	132,823		$	84,053		$	137,653
Effect of derivatives:
Net (gains) losses included in net income		(36,187	)		(36,187	)		(15,651	)		(41,906	)
Cash settlements		29,723			29,723			27,380			32,818
Loss on firm transportation commitment		17,332			17,332			—			—
Impairments		104,484			104,484			104,688			45,959
Loss (gain) on sale of assets		(4,282	)		(4,282	)		(2,474	)		61
Loss on extinguishment of debt		3,164			3,164			25,421			—
Other non-cash items		561			561			(908	)		(1,238	)
Adjusted EBITDAX	$	309,447		$	247,618		$	222,509		$	173,347

(3) Pro forma total interest expense and pro forma ratio of Adjusted EBITDAX to total interest expense assume an interest rate of 8.75% for the debt financing. Total interest includes interest expense less interest capitalized during the period.

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FORWARD-LOOKING STATEMENTS

Some of the information included herein contains “forward-looking statements” within the meaning of Section 27A of the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended. These statements use forward-looking words such as “may,” “will,” “should,” “could,” “achievable,” “anticipate,” “believe,” “expect,” “estimate,” “project” or other words and phrases of similar meaning. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition or state other “forward-looking” information. A forward-looking statement may include a statement of the assumptions or bases underlying the forward-looking statements. We believe we have chosen these assumptions or bases in good faith and that they are reasonable. However, we caution you that assumed facts or bases almost always vary from actual results, and the differences between assumed facts or bases and actual results can be material, depending on the circumstances. When considering forward-looking statements, you should keep in mind the cautionary statements in this offering memorandum and the documents we have incorporated by reference herein, including in our Annual Report on Form 10-K for the year ended December 31, 2012, or our 2012 Annual Report. These statements reflect our current views with respect to future events and are subject to various risks, uncertainties and contingencies, including, but not limited, to:

• our ability to successfully complete the acquisition of Eagle Ford Hunter, Inc., or Eagle Hunter, integrate the business of Eagle Hunter with ours and realize the anticipated benefits from the acquisition;

• any unexpected costs or delays in connection with the acquisition of Eagle Hunter;

• the volatility of commodity prices for oil, NGLs and natural gas;

• our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;

• our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;

• any impairments, write-downs or write-offs of our reserves or assets;

• the projected demand for and supply of oil, NGLs and natural gas;

• reductions in the borrowing base under our revolving credit facility, or our Revolver;

• our ability to contract for drilling rigs, supplies and services at reasonable costs;

• our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable cost and to sell the production at, or at reasonable discounts to, market prices;

• the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and natural gas reserves;

• drilling and operating risks;

• our ability to compete effectively against other 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;

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• 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 Item 1A of our 2012 Annual Report.

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. Other than as required under the securities laws, 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.

8

EX-99.2

Exhibit 99.2

Statement of Revenues and Direct Operating Expenses of the Eagle Ford Properties

(as described in Note 1)

	Year Ended December 31,
	2012
	(in thousands)
Revenues	$	72,111
Direct operating expenses		10,282
Revenues in excess of direct operating expenses	$	61,829

See accompanying notes to the Statement of Revenues and Direct Operating Expenses.

F-1

Notes to Statement of Revenues and Direct Operating Expenses of the Eagle Ford Properties (as described in Note 1)

(1) — Basis of Presentation

Penn Virginia Oil and Gas Corporation (“PVA”) and Magnum Hunter Resources Corporation (“MHR” or “the Company”) intend to enter into a stock purchase agreement (the “SPA”), in which PVA will acquire the issued and outstanding shares of Eagle Ford Hunter, Inc. (“EFH”) from MHR. Among the assets intended to be included in EFH at the time of the closing of the SPA are its working interest in 67 wells in the Eagle Ford Area of Texas referred to herein as “the Eagle Ford Properties” or “the Properties.” The SPA contains customary representations and warranties, covenants, indemnification provisions and conditions to closing.

The accompanying audited financial statement includes revenues from oil (including condensate and gas liquids) and gas production and direct operating expenses associated with the Properties. The accompanying statement varies from a complete income statement in accordance with accounting principles generally accepted in the United States of America in that it does not reflect certain indirect expenses that were incurred in connection with the ownership and operation of the Properties including, but not limited to, general and administrative expenses, interest expense and federal and state income tax expenses. These costs were not separately allocated to the Properties in the accounting records of MHR. In addition, these allocations, if made using historical general and administrative structures and tax burdens, would not produce allocations that would be indicative of the historical performance of the Properties had they been part of PVA due to differing size, structure, operations and accounting policies. The accompanying statement also does not include provisions for depreciation, depletion, amortization and accretion; as such amounts would not be indicative of the costs that will be incurred upon the allocation of the purchase price paid. Furthermore, no balance sheet has been presented because the acquired properties were not accounted for as a separate subsidiary or division of MHR and complete financial statements are not available, nor has information about the Properties operating, investing and financing cash flows been provided for similar reasons. Accordingly, the historical Statement of Revenues and Direct Operating Expenses of the Properties are presented in lieu of the full financial statements required under Item 3-05 of Securities and Exchange Commission (“SEC”) Regulation S-X.

This Statement of Revenues and Direct Operating Expenses is not indicative of the results of operations for the Properties on a go forward basis.

(2) — Summary of Significant Accounting Policies

Use of Estimates — The Statement of Revenues and Direct Operating Expenses was derived from the historical operating statements of MHR. Accounting principles generally accepted in the United States of America require management to make estimates and assumptions that affect the amounts reported in the Statement of Revenues and Direct Operating Expenses. Actual results could be different from those estimates.

Revenue Recognition — Oil and natural gas revenues reflect the sales method of accounting. Under the sales method, revenues are recognized based on actual volumes of oil and natural gas sold to purchasers. There were no significant imbalances with other revenue interest owners attributable to MHR during any of the periods presented in these statements.

F-2

Notes to Statement of Revenues and Direct Operating Expenses of the Eagle Ford Properties (as described in Note 1) — (Continued)

(2) — Summary of Significant Accounting Policies (Continued)

Direct Operating Expenses — Direct operating expenses are recognized on an accrual basis and consist of direct expenses of operating the Properties. The direct operating expenses include lease operating expenses and severance and ad valorem taxes.

Ÿ Lease operating expenses include gathering, processing, transportation, lifting costs, well repair expenses, surface repair expenses, well workover costs, and other field expenses. Lease operating expenses also include expenses directly associated with support personnel, support services, equipment, and facilities directly related to oil and natural gas production activities.

(3) — Purchasers Representing Greater than 10% of the Total

Five purchasers accounted for a total of 98% of the oil and gas sales. No other purchasers represented over 10% of the sales.

(4) — Contingencies

The activities of the MHR working interests and EFH may be subject to potential claims and litigation in the normal course of operations. MHR does not believe that any liability resulting from any pending or threatened litigation will have a material adverse effect on the operations or financial results of the Properties.

(5) — Subsequent Events

MHR has evaluated subsequent events through March 25, 2013, and has concluded no additional events need to be reported during this period.

F-3

Supplementary Oil and Gas Disclosures (Unaudited)

Supplemental Reserve Information

The following unaudited supplemental reserve information summarizes the net proved reserves of oil and gas and the standardized measure thereof for the year ended December 31, 2012 attributable to the Properties. All of the reserves are located in the United States. The reserve disclosures are based on reserve studies prepared in accordance with the guidelines established by the SEC.

There are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond the property owner’s control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all reserve estimates are to some degree subjective, the quantities of oil and gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future oil and gas sales prices may each differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. The standardized measure shown below represents estimates only and should not be construed as the current market value of the estimated oil and gas reserves attributable to the Properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions reflect additional information from subsequent development activities, production history of the Properties and any adjustments in the projected economic life of such property resulting from changes in product prices.

Estimated Quantities of Oil, NGL and Gas Reserves

The following table sets forth certain data pertaining to the Properties’ proved reserves for the year December 31, 2012.

	Oil (MBbl)			NGL (MBbl)			Gas (MMCF)
Proved-Developed and Undeveloped Reserves
December 31, 2011 Beginning balance		4,566			446			1,838
Revisions of previous estimates		5,541			242			910
Extensions, discoveries and other additions		1,392			88			352
Production		(686	)		(44	)		(167	)
December 31, 2012 Ending balance		10,813			732			2,933
December 31, 2012 Proved-developed		3,928			283			1,133

Standardized Measure of Discounted Future Net Cash Flows

Summarized below is the Standardized Measure related to the Properties’ proved oil, natural gas and NGL reserves. The following summary is based on a valuation of proved reserves using discounted cash flows based on prices as prescribed by the SEC, current costs and economic conditions and a 10% discount rate. The additions to proved reserves from the purchase of reserves in place, and new discoveries and extensions could vary significantly from year to year; additionally, the impact of changes to reflect current prices and costs of reserves proved in prior years could also be significant. Accordingly, the present value of

F-4

future net cash flows does not purport to be an estimate of the fair market value of the Properties’ proved reserves, nor should it be indicative of any trends. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money, and the risks inherent in producing oil and natural gas.

The following table sets forth estimates of the standardized measure of discounted future net cash flows from proved reserves of oil, NGLs and natural gas for the year ended December 31, 2012.

(amounts in thousands)
Estimated future cash inflows	$	1,108,293
Future development costs		(237,252	)
Future production costs		(282,400	)
Future net cash flows		588,641
Discount of future net cash flows at 10%		(347,904	)
Standardized measure of discounted future net cash flows	$	240,737

The following table sets forth a summary of the changes in the standardized measure of discounted future net cash flows from proved reserves of oil, NGLs and natural gas for the year ended December 31, 2012.

(amounts in thousands)
Balance, beginning of period	$	95,856
Net change in prices and production costs		10,054
Net change in future development costs		(60,252	)
Sales of oil and gas, net		(61,787	)
Extensions and discoveries		43,187
Revisions of previous quantity estimates		166,576
Previously estimated development costs incurred		20,944
Accretion of discount		9,586
Other		16,573
Balance, end of period	$	240,737

F-5

EX-99.3

$400MM Eagle Ford Shale Acquisition

Investor Presentation

April 3, 2013

NYSE: PVA

Exhibit

99.3

1

Forward-Looking Statements

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 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.

Oil and Gas Reserves

Effective January 1, 2010, the SEC permits oil and gas companies, in their filings with the SEC, to disclose not only “proved” reserves, but also “probable”

reserves and “possible” reserves.  As noted above, statements of reserves are only estimates and may not correspond to the ultimate quantities of oil and gas

recovered.  Any reserve estimates provided in this presentation that are not specifically designated as being estimates of proved reserves may include estimated

reserves not necessarily calculated in accordance with, or contemplated by, the SEC’s latest reserve reporting guidelines. Investors are urged to consider closely

the disclosure in PVA’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011, which is available from PVA at Four Radnor Corporate Center,

Suite 200, Radnor, PA 19087 (Attn: Investor Relations). You can also obtain this report from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at

www.sec.gov.

Definitions

Proved reserves are those quantities of oil and gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be

economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government

regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of

whether the estimate is a deterministic estimate or probabilistic estimate.  Probable reserves are those additional reserves that are less certain to be recovered

than proved reserves, but which are as likely than not to be recoverable (there should be at least a 50% probability that the quantities actually recovered will

equal or exceed the proved plus probable reserve estimates).  Possible reserves are those additional reserves that are less certain to be recoverable than

probable reserves (there should be at least a 10% probability that the total quantities actually recovered will equal or exceed the proved plus probable plus

possible reserve estimates).  “3P” reserves refer to the sum of proved, probable and possible reserves.  Estimated ultimate recovery (EUR) is the sum of reserves

remaining as of a given date and cumulative production as of that date.

Forward-Looking Statements, Oil and Gas Reserves and Definitions

Transformational

Acquisition in the

Eagle Ford Shale

•

Penn Virginia is acquiring Eagle Ford Shale assets from Magnum Hunter for approximately $400

million

•

Assets are adjacent to PVA’s current Eagle Ford position in Gonzales and Lavaca Counties

•

40,565 (19,037 net) acres in Gonzales and Lavaca counties

•

46 (22.1 net) producing wells and drilling inventory of 345 (169

net) locations

(1)

•

Approximately 3,173 BOEPD –

February 2013

•

Approximately 5,500 BOEPD –

2013E (final eight months)

•

12.0 MMBoe of proved reserves (37% PD / 96% Liquids)

(2)

Attractive

Transaction

Valuation

•

Transaction Value / Production ($ / BOEPD –

February 2013) = ~$126,000

•

Transaction Value / Production ($ / BOEPD –

2013E) = ~$73,000

•

Transaction Value / Proved Reserves ($ / BOE) = ~$33.00

•

Transaction Value / 2013E EBITDAX ($93 million over 7.5 months, annualized) = ~2.7x

Committed

Transaction

Financing

•

The transaction is not subject to any financing contingency

•

$250 million senior unsecured bridge facility is available

•

$40 million common equity (at its option, PVA can issue 10 million shares to MHR @ $4/share)

•

We intend to issue $400MM of senior unsecured notes in a private

placement

Closing Timeline

•

April 2

nd

–

PSA signed

•

April 2

nd

–

Acquisition announced

•

April 3

rd

–

Commence private placement

•

Week of April 8

th

–

Price notes placement

•

By mid-May 2013 –

Close acquisition

Transaction Overview

(1)

Inventory includes seven MHR/Hunt wells that are in the process of completion or waiting on completion.

(2)

As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.

2

•

Transformational acquisition which increases our footprint in the volatile oil window core of the

Eagle Ford Shale play

•

With 82,995 gross (54,057 net) highly contiguous acres, our pro forma position will be significant

with attractive leverage on a per share basis

•

MHR’s acreage is adjacent to our current leasehold position and has geologic and reserve

characteristics that are very comparable to our existing Eagle Ford Shale assets

•

Enhances production growth, with 2013E production (7.5 months) of approximately 5,500

BOEPD, representing a 34% increase (23% increase in BOEPD on a full-year basis)

•

Increases

drilling

inventory

in

the

Eagle

Ford

Shale

to

640

(420

net)

locations

•

Attractive drilling economics with PV-10 breakeven WTI prices of between $47 and $57 per

barrel (with and without current LLS uplift)

•

Accretive to 2013 and 2014 cash flow per share and net asset value

•

Increases proved reserve asset base by 11% by adding 12.0 MMBoe (96% liquids / 37% PD),

increases Eagle Ford Shale proved reserve base by 46%

•

Increases our ability to achieve operational efficiencies of scale

Strategic Rationale

3

4

•

Purchase price of approximately $400 million

for 19,037 highly contiguous net acres in

Gonzales and Lavaca Counties

•

Year-end 2012 SEC proved reserves of 12.0

MMBoe

(1)

–

Oil = 90% of proved reserves

–

37% proved developed

•

Year-end

2012

SEC

PV-10

of

$241

million

(1)

–

PD PV-10 of $156 million

•

Year-end reserves include 44 proved

developed locations and 51 locations booked

as PUDs

(1)

•

Expands existing footprint and acreage is largely

adjacent to existing position

•

Acquired assets add up to 345 gross (169

net) locations

Greater scale with ~54,000 net acres

in the Eagle Ford and substantial growth in oil production revenue

Transformational Acquisition

MRO

MHR

PVA

HUNT

EOG

EOG

PVA

Gonzales

Lavaca

DeWitt

3D Seismic

(1)

As of December 31, 2012 per March 28, 2013 reserve report prepared by Cawley, Gillespie & Associates.

ACREAGE

EAGLE HUNTER

PVA

OPERATOR

EOG

MAGNUM HUNTER

PVA

HUNT

MARATHON

5

10%

28%

44%

11%

9%

20%

Net Acres

Net Inventory

February 2013

Daily Production

Total Proved Oil

Reserves

Total Proved

Reserves

Proved

Developed

Reserves

54%

68%

53%

46%

45%

42%

Net Acres

Net Inventory

February 2013

Daily Production

Total Proved Oil

Reserves

Total Proved

Reserves

Proved

Developed

Reserves

Acquisition Impacts to PVA’s Asset Profile

Transformational Acquisition (cont.)

Growth in Key Corporate Metrics as a Result of Acquisition

Growth in Key Eagle Ford Metrics as a Result of Acquisition

Note: Reserves as of 12/31/2012 . All other figures current unless otherwise stated.

Acquisition Significantly Increases PVA’s Eagle Ford Position and Overall Scale in the Eagle Ford

6

Expanded Eagle Ford Acreage Position

72

67

62

60

54

54

53

40

39

35

28

28

24

22

9

7

0

10

20

30

40

50

60

70

80

90

BHP

SN

PXD

ZAZA

ROSE

COG

PXP

PVA PF

SFY

CRZO

FST

GDP

PVA

CRK

MTDR

HK

Aurora

CXPO

AXAS

Source: Company investor presentations and SEC filings.

341

138

118

(Net acreage in thousands)

•

Net acreage by operator across entire Eagle Ford play

•

Operators’

disclosed acreage includes leaseholds outside volatile oil window

•

Approximately all of PVA’s leasehold is in the volatile oil window

Note:

Some operators off map.

(1)

Based on latest company presentations, as well as industry publications.  Some industry publication information may be out of date.

PVA

MHR

Hunt

BHP

CHK

COG

COP

CRK

CRZO

EOG

FST

MRO

MUR

NFX

PXD

PXP

SFY

STO

TLM

EFS Operators

Eagle Ford Shale Operators

Eastern Volatile Oil Windows

(1)

7

Victoria

Goliad

Bee

Live Oak

McMullen

Wilson

Atascosa

Bexar

San Antonio

Texas

Volatile Oil

Condensate

Rich Gas

Gonzales

Lavaca

DeWitt

•

82,995 gross (   54,057 net) acres in Gonzales and Lavaca

Counties, TX

(1)

•

Operator

of

46,452

(32,410

net)

acres

in

Gonzales

-

70%

WI

•

Operator

of

23,203

(15,148

net)

acres

in

Lavaca

-

65%

WI(1)

•

Non-operator

of

13,340

(6,499

net)

acres

in

Gonzales

-

49%

WI

•

Avg. IP/30-day rates of 1,066/676 Boe/d

•

Gonzales

type

curve

EUR

of

400

MBoe

(2)

•

Lavaca

type

curve

EUR

of

500

MBoe

(2)

•

Proved reserves of 38.2 MMBoe at year-end 2012, consisting of

82% oil, 10% NGLs and 8% gas

•

Proved PV-10 at YE12 of $933 MM ($784MM of PD value)

•

117 (82.0 net) wells producing

•

Objective is to lower PVA well costs by at least 10-15% in 2013

•

Up to 640 (420 net) remaining drilling locations

•

Initial positive down-spacing tests of 3-well pad in Gonzales

County and 2 closely spaced MHR wells in Lavaca County

•

Includes over 300 infill locations

•

Rigs, infrastructure in place

•

Dedicated rigs and frac crew

•

Gas gathering and processing in place

•

Receiving premium LLS base pricing

(1)

Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

(2)

Based on 1/29/13 operational release, YE12 SEC reserve report prepared by Wright & Co. and YE12 SEC reserve report prepared by Cawley, Gillespie & Associates.

Premier Shale Oil & Liquids Play

Sizeable Position in a Successful Portion of the Eastern Oil Window of the Eagle Ford Shale

PVA’s Pro Forma Eagle Ford Shale Position

Gonzales

Lavaca

DeWitt

PVA Pro Forma

BHP Billiton

ConocoPhillips

EOG

Forest

Nearby Operators

Marathon

Pioneer

Plains

Statoil

8

Prospect Area

Gross

Acres

Net Acres

Average

Royalty

Peach Creek (MHR)

19,722

9,166

20%

Peach Creek (Hunt JV)

13,340

6,499

20%

Shiner (GeoSouthern JV)

4,674

2,119

20%

Shiner

2,829

1,253

20%

Total / Average

40,565

19,037

20%

Prospect Area

Producing

Wells

Gross Non-

Producing

Locations

Net Non-

Producing

Locations

Peach Creek (MHR)

27

149

73.1

Peach Creek (Hunt JV)

15

121

60.5

Shiner (GeoSouthern JV)

3

72

32.6

Shiner

1

3

3.0

Total

46

345

169.3

Total of 345 (169 net) locations across 40,565 (19,037 net) acres in Gonzales and Lavaca Counties

Acquired Asset in Detail

9

PVA vs. MHR Eagle Ford Assets

10

•

Located in Gonzalez and Lavaca

Counties

•

Total of 42,430 gross (35,020 net) acres

primarily in the volatile oil window

•

Existing assets provide a multi-year

inventory of up to 295 (251 net)

additional locations

•

Successful down-spacing tests add

potential locations to inventory

•

Recent successful wells in the southern and

eastern portions of our Lavaca acreage

have further “de-risked”

inventory

•

Also located in Gonzalez and Lavaca

Counties and largely adjacent to PVA’s

existing leaseholds

•

Total of 40,565 gross (19,037 net) acres

•

Expands our multi-year inventory with

the addition of up to 345 (169 net)

additional undrilled locations

•

Peach Creek area in Gonzales and Lavaca

Cos. has a total of 270 (133 net) locations

•

Shiner area in Lavaca Co. has a total of 75

(36 net) locations

Pro Forma Eagle Ford Shale

PVA EXISTING

MHR ASSETS TO BE ACQUIRED

Area

Producing

Wells

Remaining

Locations

Total Well

Locations

Gross

Acreage

Net

Acreage

(1)

Acres /

Location

(2)

PVA Gonzales

54

190

244

26,239

21,261

108

PVA Lavaca

17

105

122

16,191

13,759

133

Eagle Hunter

46

345

391

40,565

19,037

104

Pro Forma Total

117

640

757

82,995

54,057

110

(% Change)

65%

117%

107%

96%

54%

(1)

Net acreage in Lavaca County is expected to increase due to non-consents by our partner on initial wells in 17 drilling units.

(2)

Represents gross acres per location.

•

Due to both acquisitions and leasing efforts over the past two years, our acreage position is

now

83,000

gross

(~54,000

net)

acres

primarily

in

the

volatile

oil

window

(1)

•

We also have a multi-year inventory of up to 640 (420 net) additional drilling locations

•

Successful

down-spacing

testing

has

added

over

300

potential

infill

locations

to

our

inventory

•

Locations will vary over time in terms of lateral length, frac stages, spacing and geology

•

Recent successful wells in the southern and eastern portions of our Lavaca acreage have further

“de-risked”

our inventory

•

Unitizations with other industry participants and continued leasing are expected to yield additional

locations

11

Significant Eagle Ford Shale Acreage and Drilling Inventory

Combined Position Post Acquisition

12

Note: Excludes two Marcellus locations.

(1)

Median gross EUR for all PUD locations.

•

Total inventory of up to 1,133 gross undrilled locations (952 horizontal locations)

•

Up to 692 gross horizontal drilling locations in the Eagle Ford and Granite Wash

Pro Forma PVA Has a Healthy Inventory of Drilling Locations

Play

Gross Undrilled

Locations

Average Working

Interest

Gross EUR

(MBoe/Well)

(1)

Existing Eagle Ford (Gonzales)

190

83%

394

Existing Eagle Ford (Lavaca)

105

88%

513

Eagle Hunter

345

48%

357

Granite Wash

52

18%

809

Cotton Valley

78

71%

903

Haynesville

78

77%

869

Cotton Valley (vertical)

181

71%

172

Selma Chalk

104

96%

302

Totals

1,133

Pro Forma Total Company Drilling Inventory

•

Significant

upside

in

inventory

of

“gassy”

locations

13

2013 Capital Spending Focused on Eagle Ford Drilling

•

Full-year

2013

capital

expenditures

expected

to

be

approximately

$457

million

(1)

•

Four

operated

rigs

with

two

on

existing

PVA

acreage

and

two

rigs

on

operated

MHR

acreage

•

Two non-operated rigs

•

Incremental

capital

spending

of

approximately

$77

million

(1)

•

Six-rig drilling program (currently seven rigs running between PVA, MHR and Hunt)

•

Adjusted EBITDAX expected to increase to between $295 and $350 million, or 25% over previous guidance

•

2013 capital spending is expected to be 92% Eagle Ford

•

Maintenance and new ventures capital for other areas

Pro Forma Capital Expenditures by Area

(1)

Pro Forma Capital Expenditures by Type

(1)

Other

4%

Eagle Ford D&C

87%

Other D&C

4%

Land

5%

Revised 2013 Capital Plan

(1)

Change in mid-points of full-year 2013 guidance, adjusted for acquired Eagle Ford assets.

Other

3%

Pearsall

2%

Existing Eagle

Ford

64%

Acquired Eagle

Ford Assets

28%

Mid-Continent

3%

14

Sources & Uses / Pro Forma Capitalization

(1)

Seller has agreed to backstop transaction, ultimately in the amount of

$40 million of equity consideration.

(2)

Company estimate based on closing date of May 1, 2013.

(3)

Current borrowing base of $300 million will be adjusted to $287.5

million at closing, pending borrowing base redetermination waiver.

Calculation not inclusive of $2.1 million outstanding on letters

of credit as of December 31, 2012.

(4)

As of March 31, 2013, PVA had cash and cash equivalents of $10.7

million. Subsequently, in connection with entering into the stock

purchase agreement relating to the acquisition, PVA borrowed $5

million under its revolving credit facility and paid a $10 million deposit to

MHR, which will be applied towards the purchase price at the close of

the acquisition.

(5)

Reflects total value of convertible preferred at issuance.

(6)

Current Market Capitalization reflects share price of $3.90 as of April 2,

2013. Acquisition adjustment reflects value of 10 million shares

issued at $4.00 per share.

(7)

As of March 31, 2013, PVA had $38 million outstanding under its

revolving credit facility.

Uses

($ in millions)

Acquisition Consideration

$400

43

Estimated Fees and Expenses

15

Total Uses

$458

Sources

($ in millions)

New Senior Notes

$400

40

Draw on Revolver

18

Total Sources

$458

Pro Forma Capitalization

($ in millions)

12/31/2012

Eagle Ford Acq.

Adjustments

PVA Pro Forma

12/31/2012

(4)

$18

--

$18

(3)

-

$18

$18

10.375% Senior Notes due 2016

295

--

295

7.250% Senior Notes due 2019

300

--

300

New Senior Notes

-

400

400

Total Debt

$595

$1,013

(5)

$115

--

$115

(6)

$215

$40

$255

Enterprise Value

$907

--

$1,365

LTM Adjusted EBITDAX

$248

$62

$309

Proved Reserves (MMBoe)

113.5

12.0

125.5

% Oil

22%

90%

28%

% Liquids

40%

96%

45%

% Developed

41%

37%

41%

Q4 2012 Production (MBoe/d)

15.4

2.7

18.2

Proved R/P (Years)

20.1x

12.2x

18.9x

PD R/P (Years)

8.3x

4.4x

7.8x

PT Proved PV-10%

$693

$241

$933

Credit Statistics

Total Debt /

Proved Reserves ($ / Boe)

$5.24

$8.07

PD Reserves ($ / Boe)

12.66

19.72

LTM Adj. EBITDA

2.4x

3.3x

PT Proved PV-10% / Total Debt

1.2x

0.9x

Total Debt / EV

66%

74%

(3)(7)

$300

$269

Pro forma for the acquisition, PVA has

~$269 million of undrawn liquidity on

its

revolving

credit

facility

(3)

Post Closing Adjustments

Equity Issuance

(1)

(2)

Cash and Cash Equivalents

Current Undrawn Facility

Revolving Credit Facility

6% Convertible Preferred

Market Capitalization

15

Quarterly Adjusted EBITDAX and EBITDAX Margin ($ / Boe)

Comparative Q4 2012 EBITDAX Margins ($ / Boe)

(2)

•

EBITDAX has increased significantly since mid-2010 when we shifted our strategy to oil and NGLs

•

Cash margin per Boe has also improved significantly due to the increase in oil prices and declining

operating costs per unit

•

Eagle Ford cash margin was $79.00 / Boe in 4Q12

(1)

Source: Company filings.

(1)

Excludes regional and corporate G&A expenses.

(2)

PVA 4Q2012 EBITDAX of $62.3 million per its earnings release. EBITDAX for peers calculated as total revenues less lease operating expenses,

production taxes and cash G&A unless otherwise disclosed.  Inclusive of realized hedge gains or losses.

(3)

Pro forma for the Acquisition.

Strong Margins vs. Peers

$48.41

$45.88

$43.72

$40.61

$39.10

$36.48

$26.37

$25.01

$24.54

$22.95

$19.79

$13.56

PVA

PF

GDP

PVA

CWEI

CRZO

FST

PDCE

BBG

CRK

Antero

XCO

KWK

(3)

$49

$33

$46

$45

$44

$48

$66

$62

$64

$61

$60

$62

1Q10

2Q10

3Q10

4Q10

1Q11

2Q11

3Q11

4Q11

1Q12

2Q12

3Q12

4Q12

16

Revised for Proposed MHR Acquisition Assuming 5/15/13 Closing Date

Full-Year 2013 Guidance Table

2,775

-

3,075

760

-

890

3,535

-

3,965

730

-

820

55

-

75

785

-

895

13,000

-

13,650

190

-

240

13,190

-

13,890

5,672

-

6,170

847

-

1,005

6,518

-

7,175

15,539

-

16,904

3,681

-

4,370

17,858

-

19,658

59.9%

-

64.9%

95.3%

-

96.8%

64.5%

-

69.4%

$265.0

-

$293.5

$70.0

-

$80.0

$335.0

-

$373.5

21.5

-

24.5

1.5

-

2.0

23.0

-

26.5

43.5

-

45.5

1.0

-

1.5

44.5

-

47.0

$330.0

-

$363.5

$72.5

-

$83.5

$402.5

-

$447.0

$58.18

-

$58.91

$85.63

-

$83.08

$61.75

-

$62.30

86.2%

-

88.0%

97.9%

-

98.8%

88.3%

-

90.0%

$4.60

-

$5.00

$4.65

-

$5.05

$1.70

-

$1.90

$1.45

-

$1.65

6.3%

-

6.9%

6.6%

-

7.1%

$39.5

-

$40.5

$1.8

-

$2.0

$41.3

-

$42.5

3.0

-

4.0

0.2

-

0.3

3.2

-

4.3

2.5

-

2.7

2.5

-

2.7

$42.5

-

$44.5

$4.5

-

$5.0

$47.0

-

$49.5

$28.0

-

$30.0

$18.0

-

$22.0

$46.0

-

$52.0

21.0

-

22.0

21.0

-

24.0

42.0

-

46.0

$36.00

-

$39.00

$36.00

-

$39.00

$234.5

-

$280.0

$60.0

-

$70.0

$294.5

-

$350.0

$310.0

-

$345.0

$80.0

-

$85.0

$390.0

-

$430.0

17.0

-

18.0

(2.5)

-

(2.0)

14.5

-

16.0

5.0

-

7.0

(2.5)

-

(2.0)

2.5

-

5.0

28.0

-

30.0

(3.0)

-

1.0

25.0

-

31.0

$360.0

-

$400.0

$72.0

-

$82.0

$432.0

-

$482.0

Pro Forma

2013 Guidance

Current Full-Year

2013 Guidance

Adjustments for MHR

Acquisition / One Less Rig

(a)

Assumes average benchmark prices of $90.96 per barrel for crude oil and $3.51 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 $29.38 per barrel.

Production:

Crude oil (MBbls)

NGLs (MBbls)

Natural gas

(MMcf)

Equivalent production

Percent crude oil and NGLs

Production revenues (a):

Crude oil

NGLs

Natural gas

Total product revenues

Total product revenues ($ per BOE)

Percent crude oil and NGLs

Operating expenses:

  Lease operating

($ per BOE)

Adjusted EBITDAX (b)

Capital expenditures:

Drilling and completion

Pipeline, gathering, facilities

Seismic (c)

Lease acquisitions, field projects and other

  Total oil and gas capital expenditures

Depreciation, depletion and amortization

($ per BOE)

(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 .

(MBOE)

Equivalent

daily

production

(BOEPD)

General and administrative:

  Recurring general and administrative

  Share-based compensation

  Restructuring

Total reported G&A

Exploration:

Total reported exploration

  Unproved property amortization

  Gathering, processing and trans. cost($ per BOE)

  Production and ad valorem taxes

(% of oil and gas revenues)

17

PVA Proved Reserves

(1)

Oil

(MMBbls)

NGLs

(MMBbls)

Natural Gas

(Bcfe)

Oil Equivalents

(MMBoe)

SEC PV-10

($mm)

Proved Developed

10.5

8.3

169.4

47.0

$627.9

Proved Undeveloped

14.4

12.4

238.1

66.5

64.5

Total Proved Reserves

24.9

20.7

407.5

113.5

$692.5

(1)     Prepared by Wright & Company, Inc. based on adjusted product prices of $102.24 per barrel of oil, $39.48 per barrel of NGLs and $2.47 per Mcf of gas.

(2)     Prepared by Cawley, Gillespie & Associates, Inc. for Magnum Hunter based on average prices of $98.77 per barrel of oil, $2.88 per Mcf of gas and $43.57 per barrel of NGL.

SEC Proved Reserve Disclosure

Acquired Eagle Ford Assets

(2)

Oil

(MMBbls)

NGLs

(MMBbls)

Natural Gas

(Bcfe)

Oil Equivalents

(MMBoe)

SEC PV-10

($mm)

Proved Developed

3.9

0.3

1.1

4.4

$156.0

Proved Undeveloped

6.9

0.4

1.8

7.6

84.7

Total Proved Reserves

10.8

0.7

2.9

12.0

$240.7

Pro Forma Proved Reserves

Oil

(MMBbls)

NGLs

(MMBbls)

Natural Gas

(Bcfe)

Oil Equivalents

(MMBoe)

SEC PV-10

($mm)

Proved Developed

14.4

8.5

170.6

51.4

$784.0

Proved Undeveloped

21.3

12.9

239.9

74.1

149.3

Total Proved Reserves

35.7

21.4

410.5

125.5

$933.2

Penn Virginia Corporation

4 Radnor Corporate Center, Suite 200

Radnor, PA 19087

610-687-8900

www.pennvirginia.com