UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

________________________________________________________

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2013 

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number: 1-13283

 _________________________________________________________ 

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification Number)

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

__________________________________________________________

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 ("Exchange Act") during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý  No  ¨

 Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer	¨	Accelerated filer	ý
Non-accelerated filer	¨	Smaller reporting company	¨

 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  ý

 As of May 3, 2013, 65,222,907 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

 FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2013

Table of Contents

Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended March 31, 2013 and 2012	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended March 31, 2013 and 2012	4
	Condensed Consolidated Balance Sheets as of March 31, 2013 and December 31, 2012	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2013 and 2012	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Acquisitions and Divestitures	8
	4. Accounts Receivable and Major Customers	9
	5. Derivative Instruments	9
	6. Property and Equipment	12
	7. Long-Term Debt	12
	8. Additional Balance Sheet Detail	13
	9. Fair Value Measurements	15
	10. Commitments and Contingencies	16
	11. Shareholders' Equity	17
	12. Share-Based Compensation	18
	13. Restructuring and Exit Activities	18
	14. Interest Expense	19
	15. Earnings per Share	19
Forward-Looking Statements		20
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations:
	Overview of Business	21
	Key Developments	21
	Results of Operations	24
	Liquidity and Capital Resources	30
	Environmental Matters	34
	Critical Accounting Estimates	35
	New Accounting Standards	35
3.	Quantitative and Qualitative Disclosures About Market Risk	36
4.	Controls and Procedures	38
Part II - Other Information
1A.	Risk Factors	39
6.	Exhibits	40
Signatures		41

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

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
(Loss) gain 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	10,943			12,141
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 from operations 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 attributable 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

See accompanying notes to condensed consolidated financial statements.

3

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - unaudited

(in thousands) 

	Three Months Ended March 31,
	2013			2012
Net loss	$	(16,383	)	$	(11,899	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $10 in 2013 and $13 in 2012	19			23
	19			23
Comprehensive loss	$	(16,364	)	$	(11,876	)

See accompanying notes to condensed consolidated financial statements.

4

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands, except share data)

	As of
	March 31,			December 31,
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	14,422		$	17,650
Accounts receivable, net of allowance for doubtful accounts	64,378			62,978
Derivative assets	5,900			11,292
Other current assets	3,961			4,595
Total current assets	88,661			96,515
Property and equipment, net (successful efforts method)	1,760,240			1,723,359
Derivative assets	3,608			5,181
Other assets	17,292			17,934
Total assets	$	1,869,801		$	1,842,989
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	121,967		$	111,655
Derivative liabilities	4,539			—
Deferred income taxes	573			370
Total current liabilities	127,079			112,025
Other liabilities	28,518			28,901
Derivative liabilities	1,235			1,421
Deferred income taxes	202,196			210,767
Long-term debt	633,080			594,759
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; 11,500 shares issued as of March 31, 2013 and December 31, 2012 with a redemption value of $10,000 per share	1,150			1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 55,222,907 and 55,117,346 shares issued as of March 31, 2013 and December 31, 2012, respectively	365			364
Paid-in capital	849,710			849,046
Retained earnings	27,682			45,790
Deferred compensation obligation	3,176			3,111
Accumulated other comprehensive loss	(963		)	(982		)
Treasury stock – 234,253 and 218,320 shares of common stock, at cost, as of March 31, 2013 and December 31, 2012, respectively	(3,427		)	(3,363		)
Total shareholders’ equity	877,693			895,116
Total liabilities and shareholders’ equity	$	1,869,801		$	1,842,989

See accompanying notes to condensed consolidated financial statements.

5

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

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 stock	(1,687		)	—
Dividends paid on common stock	—			(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:
Cash paid for:
Interest (net of amounts capitalized)	$	340		$	557
Income taxes (net of refunds received)	$	—		$	(301	)

See accompanying notes to condensed consolidated financial statements.

6

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS - unaudited

For the Quarterly Period Ended March 31, 2013

(in thousands, except per share amounts)

1.  Organization

Penn Virginia Corporation (“Penn Virginia,”, “we,” “us” or “our”) is an independent oil and gas company engaged primarily in the exploration, development and production of oil, natural gas liquids (“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.

2. Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America ("U.S. GAAP"). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2012. Operating results for the three months ended March 31, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. Certain amounts for the 2012 period have been reclassified to conform to the current year presentation.

During the quarter ended March 31, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 11. The adoption of ASU 2013-02 did not have a significant impact on our Condensed Consolidated Financial Statements and Notes.

Management has evaluated all activities of the Company, through the date upon which our Condensed Consolidated Financial Statements were issued, and concluded that, except for the transactions discussed below, no additional subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.

Subsequent Events

The transactions described below occurred subsequent to the closing of our quarterly reporting period that ended on March 31, 2013 and will be recorded during the second quarter of 2013. Because these transactions are significant to us, we are providing disclosures required by U.S. GAAP.

On April 24, 2013 (the “Date of Acquisition”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from Magnum Hunter Resources Corporation (“MHR”) for approximately $400 million (the “Acquisition”) consisting of approximately $360 million in cash and 10 million shares of our common stock (the “Shares”) with an effective date of January 1, 2013. See Note 11 for a description of the rights and obligations related to the Shares issued to MHR. The Acquisition includes approximately 40,600 gross (19,000 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired assets also include working interests in 46 gross (22.1 net) producing wells. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 million barrels of oil equivalent, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.

We will account for the Acquisition by applying the acquisition method of accounting in the second quarter of 2012. The initial accounting for the Acquisition as presented below is based upon preliminary information and was not complete as of the date our Condensed Consolidated Financial Statements were issued. Accordingly, adjustments to the initial accounting for the acquired net assets will likely occur as we obtain additional information and complete a more detailed analysis regarding the facts and circumstances that existed as of the Date of Acquisition.

7

The following table represents the preliminary fair values of the net assets acquired at the Date of Acquisition:

Assets
Oil and gas properties - proved	$	247,709
Oil and gas properties - unproved	172,367
Other assets	15,100
	435,176
Liabilities
Accounts payable and accrued expenses	(31,000		)
Other liabilities	(1,500		)
	(32,500		)
Net asset acquired	$	402,676

The fair values of the net assets acquired were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to valuation of oil and natural gas properties include estimates of: (i) reserves, (ii) future operating and development costs, (iii) future commodity prices, (iv) estimated future cash flows and (v) a market-based weighted-average cost of capital. Because many of these inputs are not observable, we have classified the initial fair value estimates as Level 3 inputs as that term is defined in U.S. GAAP.

The results of operations attributable to the Acquisition from the Date of Acquisition will be included in our Condensed Consolidated Financial Statements for the period ended June 30, 2013. The following table presents unaudited summary pro forma financial information for the year ended December 31, 2012 assuming the Acquisition occurred as of January 1, 2012. The pro forma financial information does not purport to represent what our results of operations would have been if the Acquisition had occurred as of this date or the results of operations for any future periods.

Total revenues	$	389,260
Net loss	$	(160,555	)
Loss per share - basic and diluted	$	(2.77	)

On April 11, 2013, we initiated a tender offer (the “Tender Offer”) for any and all of the total $300 million principal amount of our 10.375% Senior Notes due 2016 (the “2016 Senior Notes”). As of April 24, 2013, holders of approximately 58% of the $300 million total principal amount of the 2016 Senior Notes outstanding had tendered their 2016 Senior Notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered by April 24, 2013, was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. On April 25, 2013, we paid a total of approximately $191 million, including accrued interest of $6.5 million, for the 2016 Senior Notes tendered. On May 6, 2013, we made an irrevocable election to redeem (the "Redemption") on May 10, 2013 the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We will pay a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes in connection with the Redemption. We will recognize a loss on the extinguishment of debt of approximately $29 million in connection with the Tender Offer and the Redemption, which will be recorded in the second quarter of 2013.

On April 24, 2013, we completed a private placement of $775 million of 8.5% Senior Notes due 2020 Senior Notes (the “2020 Senior Notes”). The 2020 Senior Notes were priced at par and interest will be payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by all of our material subsidiaries (the “Guarantor Subsidiaries”). Approximately $380 million of the net proceeds from the private placement, together with the Shares, were used to finance the Acquisition, including purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the revolving credit facility (the “Revolver”) and to fund a portion of the Tender Offer and the Redemption.

3. Acquisitions and Divestitures

Divestitures

In 2012, we sold our legacy natural gas assets in West Virginia, Kentucky and Virginia. The assignment of certain properties in West Virginia subject to this sale was not completed until January 2013 at which time we received $0.5 million in proceeds, net of transaction costs.

8

4.       Accounts Receivable and Major Customers

The following table summarizes our accounts receivable by type as of the dates presented:

	As of
	March 31,			December 31,
	2013			2012
Customers	$	49,978		$	43,967
Joint interest partners	13,197			16,154
Other	2,851			4,523
	66,026			64,644
Less: Allowance for doubtful accounts	(1,648		)	(1,666		)
	$	64,378		$	62,978

For the three months ended March 31, 2013, four customers accounted for $46.2 million, or approximately 56%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2013 were $16.1 million, $10.9 million, $10.6 million and $8.6 million or 20%, 13%, 13% and 10% of the consolidated total, respectively. As of March 31, 2013, $23.8 million, or approximately 37% of our consolidated accounts receivable, including joint interest billings, related to these customers. For the three months ended March 31, 2012, two customers accounted for $32.9 million, or approximately 40% of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2012 were $16.8 million and $16.1 million, or approximately 20% and 19% of the consolidated total, respectively. As of December 31, 2012, $10.1 million, or approximately 16% of our consolidated accounts receivable, including joint interest billings, related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

5. Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility as well as the volatility in interest rates attributable to our debt instruments. Our derivative instruments are not formally designated as hedges. The disclosures included herein incorporate the requirements of Accounting Standards Update No. 2011-11, Disclosures about Offsetting Assets and Liabilities as amended by Accounting Standards Update No. 2013-01, Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.

Commodity Derivatives

We utilize collars, swaps and swaptions, which are placed with financial institutions that we believe are acceptable credit risks, to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements.

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. A 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 the term of the swaption is higher than or equal to the swaption strike price on the exercise date, the counterparty will exercise its option to enter into a fixed price swap at the swaption strike price for the term of the swaption, at which point the contract functions as a fixed price swap. If the forward commodity price for the term of the swaption is lower than the swaption strike price on the exercise date, the option expires and no fixed price swap is in effect.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.

9

The following table sets forth our commodity derivative positions as of March 31, 2013:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2013	Collars	1,900	$	90.00	$	99.17	$	—	$	164
Third quarter 2013	Collars	1,900	$	90.00	$	99.17	—		235
Fourth quarter 2013	Collars	1,900	$	90.00	$	99.17	—		81
Second quarter 2013	Swaps	3,750	$	101.26			1,460		173
Third quarter 2013	Swaps	4,000	$	98.43			1,038		550
Fourth quarter 2013	Swaps	4,000	$	98.43			1,355		357
First quarter 2014	Swaps	4,000	$	95.27			1,093		720
Second quarter 2014	Swaps	4,000	$	95.27			1,312		519
Third quarter 2014	Swaps	3,500	$	94.43			1,096		347
Fourth quarter 2014	Swaps	3,500	$	94.43			1,199		210
First quarter 2014	Swaptions	1,812	$	100.00			—		281
Second quarter 2014	Swaptions	1,812	$	100.00			—		280
Third quarter 2014	Swaptions	1,812	$	100.00			—		280
Fourth quarter 2014	Swaptions	1,812	$	100.00			—		280
Natural Gas:		(in MMBtu)	($/MMBtu)
Second quarter 2013	Collars	10,000	$	3.50	$	4.30	—		34
Third quarter 2013	Collars	10,000	$	3.50	$	4.30	—		125
Fourth quarter 2013	Collars	15,000	$	3.67	$	4.37	15		222
First quarter 2014	Collars	5,000	$	4.00	$	4.50	—		58
Second quarter 2013	Swaps	15,000	$	3.92			13		151
Third quarter 2013	Swaps	15,000	$	3.92			—		271
Fourth quarter 2013	Swaps	10,000	$	4.04			—		160
First quarter 2014	Swaps	5,000	$	4.05			—		145
Second quarter 2014	Swaps	10,000	$	4.03			—		53
Third quarter 2014	Swaps	10,000	$	4.03			—		105
Settlements to be received in subsequent period							954		—

Interest Rate Swaps

In February 2012, we entered into an interest rate swap agreement to establish variable interest rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds. As of March 31, 2013, we had no interest rate derivative instruments outstanding.

10

Financial Statement Impact of Derivatives

The impact of our derivatives activities on income is included in the Derivatives caption on our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended March 31,
	2013			2012
Impact by contract type:
Commodity contracts	$	(7,761	)	$	294
Interest rate contracts	—			(599		)
	$	(7,761	)	$	(305	)
Realized and unrealized impact:
Cash received for:
Commodity contract settlements	$	3,557		$	7,981
Interest rate contract settlements	—			—
	3,557			7,981
Unrealized losses attributable to:
Commodity contracts	(11,318		)	(7,687		)
Interest rate contracts	—			(599		)
	(11,318		)	(8,286		)
	$	(7,761	)	$	(305	)

The effects of derivative gains and losses and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net loss to net cash provided by operating activities. These items are recorded in the Derivative contracts: Net losses and Derivative contracts: Cash settlements captions on our Condensed Consolidated Statements of Cash Flows.

The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments, on our Condensed Consolidated Balance Sheets as of the dates presented:

		Fair Values as of
		March 31, 2013				December 31, 2012
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	5,900	$	4,539	$	11,292	$	—
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		5,900		4,539		11,292		—
Commodity contracts	Derivative assets/liabilities - noncurrent	3,608		1,235		5,181		1,421
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		3,608		1,235		5,181		1,421
		$	9,508	$	5,774	$	16,473	$	1,421

As of March 31, 2013, we reported a commodity derivative asset of $9.5 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

11

6. Property and Equipment

The following table summarizes our property and equipment as of the dates presented: 

	As of
	March 31,			December 31,
	2013			2012
Oil and gas properties:
Proved	$	2,362,690		$	2,277,811
Unproved	54,641			60,746
Total oil and gas properties	2,417,331			2,338,557
Other property and equipment	95,221			93,648
Total property and equipment	2,512,552			2,432,205
Accumulated depreciation, depletion and amortization	(752,312		)	(708,846		)
	$	1,760,240		$	1,723,359

7. Long-Term Debt

The following table summarizes our long-term debt as of the dates presented:

	As of
	March 31,		December 31,
	2013		2012
Revolving credit facility	$	38,000	$	—
Senior notes due 2016, net of discount (principal amount of $300,000)	295,080		294,759
Senior notes due 2019	300,000		300,000
	$	633,080	$	594,759

Revolving Credit Facility

The Revolver provides for a $300 million revolving commitment and an accordion feature that allows us to increase the commitment by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver was established at $300 million. Subsequent to the private placement of the 2020 Senior Notes in April 2013, as discussed in Note 2, our borrowing base under the Revolver was reduced by $23.8 million to $276.2 million. The borrowing base will be re-determined by the end of May 2013, and semi-annually thereafter, based on a review of our total proved oil, NGL and natural gas reserves. Proved oil, NGL and natural gas reserves from the Acquisition will be considered in the May 2013 re-determination. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $2.8 million outstanding as of March 31, 2013. As of March 31, 2013, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $259.2 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of March 31, 2013, the actual interest rate on the outstanding borrowings under the Revolver was 1.75%.

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The Revolver is guaranteed by Penn Virginia and the Guarantor Subsidiaries. The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.

The guarantees provided by Penn Virginia, which is the parent company of all of our subsidiaries, and the Guarantor Subsidiaries under the Revolver as well as those provided for the senior indebtedness described below are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company and its non-guarantor subsidiaries have no material independent assets or operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends or other means, including advances and intercompany notes, among others.

The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.5 to 1.0 through December 31, 2013, 4.25 to 1.0 through June 30, 2014 and then 4.0 to 1.0 through maturity.

2016 Senior Notes

The 2016 Senior Notes were originally sold at 97% of par in June 2009, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries. As discussed in Note 2, none of the $300 million principal amount of the 2016 Senior Notes will remain outstanding subsequent to May 10, 2013 as a result of the Tender Offer and the Redemption.

2019 Senior Notes

The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. Beginning in April 2015, we may redeem all or part of the 2019 Senior Notes at a redemption price starting at 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

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8. Additional Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the dates presented:

	As of
	March 31,		December 31,
	2013		2012
Other current assets:
Tubular inventory and well materials	$	2,879	$	4,033
Prepaid expenses	1,082		562
	$	3,961	$	4,595
Other assets:
Debt issuance costs	$	12,613	$	13,186
Assets of supplemental employee retirement plan (“SERP”)	3,401		3,237
Other	1,278		1,511
	$	17,292	$	17,934
Accounts payable and accrued liabilities:
Trade accounts payable	$	31,335	$	37,835
Drilling costs	43,858		37,703
Royalties	13,559		14,390
Production and franchise taxes	4,820		2,874
Compensation - related	2,713		6,853
Interest	19,072		5,828
Preferred stock dividends	1,725		1,687
Other	4,885		4,485
	$	121,967	$	111,655
Other liabilities:
Firm transportation obligation	$	13,870	$	14,333
Asset retirement obligations (“AROs”)	4,551		4,513
Defined benefit pension obligations	1,786		1,821
Postretirement health care benefit obligations	2,699		2,634
Deferred compensation - SERP obligation and other	3,469		3,310
Other	2,143		2,290
	$	28,518	$	28,901

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9. Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to pay to transfer a liability in an orderly transaction with market participants at the measurement date.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of March 31, 2013, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

The following table summarizes the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for these debt obligations, as of the dates presented:

	As of
	March 31, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2016	$	318,000	$	295,080	$	316,500	$	294,759
Senior Notes due 2019	298,875		300,000		286,500		300,000
	$	616,875	$	595,080	$	603,000	$	594,759

Recurring Fair Value Measurements

Certain financial assets and liabilities are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheets. The following tables summarize the valuation of those assets and liabilities as of the dates presented:

	As of March 31, 2013
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	5,900		$	—		$	5,900		$	—
Commodity derivative assets - noncurrent	3,608			—			3,608			—
Assets of SERP	3,401			3,401			—			—
Liabilities:
Commodity derivative liabilities - current	(4,539		)	—			(4,539		)	—
Commodity derivative liabilities - noncurrent	(1,235		)	—			(1,235		)	—
Deferred compensation - SERP obligation	(3,464		)	(3,464		)	—			—

	As of December 31, 2012
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	11,292		$	—		$	11,292		$	—
Commodity derivative assets - noncurrent	5,181			—			5,181			—
Assets of SERP	3,237			3,237			—			—
Liabilities:
Commodity derivative liabilities - noncurrent	(1,421		)	—			(1,421		)	—
Deferred compensation - SERP obligation	(3,305		)	(3,305		)	—			—

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three months ended March 31, 2013 and 2012.

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We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

• Commodity derivatives: We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for West Texas Intermediate crude oil and NYMEX Henry Hub gas closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

• Assets of SERP: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.

• Deferred compensation - SERP obligations and other: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. The fair values are based on quoted market prices, which are level 1 inputs.

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of AROs. The factors used to determine fair value for purposes of impairment testing include, but are not limited to, estimates of proved and probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs are typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial fair value estimates as level 3 inputs.

10.    Commitments and Contingencies

Drilling and Completion Commitments

We have agreements to purchase oil and gas well drilling and well completion services from third parties with original terms of up to 3 years. As of March 31, 2013, there were no well drilling or well completion agreements with terms that extended beyond September 30, 2013. The well drilling agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term and declines as time passes. As of March 31, 2013, the penalty amount would have been $3.8 million if we had terminated our agreements on that date.

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of March 31, 2013. In addition to the reserve for litigation, we maintain a suspense account which includes approximately $1.8 million representing the excess of revenues received over costs incurred attributable to these properties. As of March 31, 2013, we also have AROs of approximately $4.6 million attributable to the plugging of abandoned wells.

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11. Shareholders’ Equity

The following tables summarizes the components of our shareholders' equity and the changes therein as of and for the three months ended March 31, 2013 and 2012:

	As of												As of
	December 31,						Dividends			All Other			March 31,
	2012			Net Loss			Declared 1			Changes			2013
Preferred stock	$	1,150		$	—		$	—		$	—		$	1,150
Common stock	364			—			—			1			365
Paid-in capital	849,046			—			—			664			849,710
Retained earnings	45,790			(16,383		)	(1,725		)	—			27,682
Deferred compensation obligation	3,111			—			—			65			3,176
Accumulated other comprehensive loss 2	(982		)	—			—			19			(963		)
Treasury stock	(3,363		)	—			—			(64		)	(3,427		)
	$	895,116		$	(16,383	)	$	(1,725	)	$	685		$	877,693
	As of												As of
	December 31,						Dividends			All Other			March 31,
	2011			Net Loss			Declared 3			Changes			2012
Common stock	$	270		$	—		$	—		$	1		$	271
Paid-in capital	690,131			—			—			1,614			691,745
Retained earnings	157,242			(11,899		)	(2,586		)	—			142,757
Deferred compensation obligation	3,620			—			—			40			3,660
Accumulated other comprehensive loss 2	(1,084		)	—			—			23			(1,061		)
Treasury stock	(3,870		)	—			—			(41		)	(3,911		)
	$	846,309		$	(11,899	)	$	(2,586	)	$	1,637		$	833,461

_______________________

¹ Includes dividends of $150.00 per share of 6% Convertible Perpetual Preferred Stock (the “6% Preferred Stock”).

² The Accumulated other comprehensive loss ("AOCL") is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCL for the three months ended March 31, 2013 and 2012 represent reclassifications from AOCL to net periodic benefit expense, a component of General and administrative expenses, of $29 and $36 and are presented above net of taxes of $10 and $13.

³ Includes dividends of $0.05625 per share of common stock.

As discussed in Note 2, we issued the Shares to MHR in April 2013 as part of the total consideration paid in connection with the Acquisition. The Shares were not registered in connection with their issuance. In connection with the Shares issued to MHR, we entered into a Registration Rights, Lock-Up and Buy-Back Agreement (the “Registration Rights Agreement”) and a Standstill Agreement (the “Standstill Agreement”). The Registration Rights Agreement requires us to file a resale registration statement (the “Registration Statement”) with respect to the Shares promptly following the closing date of the Acquisition and use our commercially reasonable efforts to cause the Registration Statement to become effective as promptly as practicable. In limited circumstances, MHR will have piggyback registration rights.

Under the Registration Rights Agreement, we are obligated, at MHR's election, to use up to 50% of the net proceeds of any public or private offering of our common stock prior to the effectiveness of the Registration Statement, and 25% of such net proceeds after the effectiveness of the Registration Statement, to repurchase Shares. This buyback obligation will terminate on the first anniversary of the effective date of the Registration Statement or, if earlier, the date upon which the Shares owned by MHR constitute less than 5% of our outstanding common stock.

Under the Standstill Agreement, MHR may not take certain actions intended to cause a change in control of us and has granted an irrevocable proxy to vote the Shares. The Standstill Agreement will terminate on April 24, 2016 or, if earlier, the date upon which the Shares owned by MHR constitute less than 10% of our outstanding common stock.

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12. Share-Based Compensation

Our stock compensation plans (collectively, the “Stock Compensation Plans”) permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We recognize compensation expense related to our Stock Compensation Plans in the General and administrative caption on our Condensed Consolidated Statement of Operations.

With the exception of performance-based restricted stock units (“PBRSUs”), all of the awards issued under our Stock Compensation Plans are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards is measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.

The following table summarizes our share-based compensation expense recognized for the periods presented:

	Three Months Ended March 31,
	2013		2012
Equity-classified awards:
Stock option awards	$	792	$	1,208
Common, deferred and restricted stock and stock unit awards	293		407
	1,085		1,615
Liability-classified awards	14		72
	$	1,099	$	1,687

13. Restructuring and Exit Activities

During 2012, we completed an organizational restructuring in conjunction with the sale of our legacy natural gas assets in West Virginia, Kentucky and Virginia. We terminated approximately 30 employees and closed our regional office in Canonsburg, Pennsylvania. In addition, we have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale, we no longer have production to satisfy this commitment. While we intend to sell our unused firm transportation in the future to the extent possible, we recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The activity summarized below includes contractual payments on the obligation as well as the recognition of accretion expense.

The following table summarizes our restructuring and exit activity-related obligations and the changes therein as of and for the periods presented:

	Three Months Ended March 31,
	2013			2012
Balance at beginning of period	$	17,263		$	576
Employee, office and other costs accrued, net	—			(3		)
Accretion of firm transportation obligation	207			—
Cash payments, net	(498		)	(98		)
Balance at end of period	$	16,972		$	475

Restructuring charges are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations. The initial charge for the firm transportation commitment was presented as a separate caption on our Consolidated Statement of Operations for the year ended December 31, 2012. The accretion of this obligation, net of any recoveries from the periodic sale of our contractual capacity, is charged as an offset to Other revenue. The current portion of these restructuring and exit cost obligations is included in the Accounts payable and accrued expenses caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of March 31, 2013, $3.0 million of the total obligations are classified as current while the remaining $14.0 million are classified as noncurrent.

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14. Interest Expense

The following table summarizes the components of interest expense for the periods presented:

	Three Months Ended March 31,
	2013			2012
Interest on borrowings and related fees	$	13,583		$	14,017
Accretion of original issue discount	321			333
Amortization of debt issuance costs	626			682
Capitalized interest	(51		)	(258		)
	$	14,479		$	14,774

15. Earnings per Share

The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:

	Three Months Ended March 31,
	2013			2012
Net loss	(16,383		)	(11,899		)
Less: Preferred stock dividends	(1,725		)	—
Loss attributable to common shareholders - Basic and Diluted	$	(18,108	)	$	(11,899	)
Weighted-average shares - Basic	55,341			45,945
Effect of dilutive securities 1	—			—
Weighted-average shares - Diluted	55,341			45,945

_______________________

¹ For the three months ended March 31, 2013 and 2012, respectively, approximately 19.2 million and less than 0.1 million potentially dilutive securities, including the 6% Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

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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, or the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: 

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

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

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

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

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

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

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

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

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

• drilling and operating risks;

• our ability to compete effectively against other independent and major oil and natural gas companies;

• our ability to successfully monetize select assets and repay our debt;

• leasehold terms expiring before production can be established;

• environmental liabilities that are not covered by an effective indemnity or insurance;

• the timing of receipt of necessary regulatory permits;

• the effect of commodity and financial derivative arrangements;

• our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;

• the occurrence of unusual weather or operating conditions, including force majeure events;

• our ability to retain or attract senior management and key technical employees;

• counterparty risk related to their ability to meet their future obligations;

• changes in governmental regulations or enforcement practices, especially with respect to environmental, health and safety matters;

• uncertainties relating to general domestic and international economic and political conditions; and

• other risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2012.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. 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.

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Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are an independent oil and gas company engaged in the exploration, development and production of oil, natural gas liquids, or NGLs, and natural gas in various domestic onshore regions. We have a geographically diverse asset base with active operations in Texas, the Mid-Continent and Mississippi regions. Our operations are concentrated primarily in the Eagle Ford Shale, and to a lesser extent, the Granite Wash, Haynesville Shale, Cotton Valley and Selma Chalk plays. As of December 31, 2012, we had proved oil and natural gas reserves of approximately 113.5 million barrels of oil equivalent, or MMBOE. Our current operations consist primarily of the drilling of unconventional horizontal development wells in shale formations.

We are currently focused on development and expansion in the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in the Mid-Continent region through participation in wells drilled by our joint venture partner.

The following table sets forth certain summary operating and financial statistics for the periods presented: 

	Three Months Ended March 31,
	2013		2012
Total production (MBOE)	1,427.1		1,812.4
Daily production (BOEPD)	15,857		19,916
Product revenues, as reported	$	82,224	$	82,680
Product revenues, as adjusted for derivatives	$	85,781	$	90,661
Cash provided by operating activities	$	45,615	$	70,701
Cash paid for capital expenditures	$	85,973	$	94,469
Cash and cash equivalents at end of period	$	14,422	$	1,936
Debt outstanding, net of discounts, at end of period	$	633,080	$	717,639
Liquidation preference of convertible preferred stock outstanding at end of period	$	115,000	$	—
Credit available under revolving credit facility at end of period 1	$	259,222	$	179,600
Net development wells drilled	8.5		7.5
Net exploratory wells drilled	—		1.9

______________________________

¹ As reduced by outstanding borrowings and letters of credit and limited by financial covenants, if applicable.

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Key Developments

The following general business developments and corporate actions will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) completing our acquisition of Magnum Hunter Resource Corporation's, or MHR, Eagle Ford Shale assets, or the Acquisition, (ii) drilling results in the Eagle Ford Shale and other plays, (iii) initiating a tender offer, or the Tender Offer, for our 10.375% Senior Notes due 2016, or 2016 Senior Notes, as well as a redemption, or the Redemption, for all 2016 Senior Notes not acquired through the Tender Offer (v) completing a private placement of $775 million of 8.5% Senior Notes due 2020, or 2020 Senior Notes, to finance the Acquisition and the Tender Offer and (vi) hedging a portion of our oil and natural gas production through calendar year 2014 to the levels permitted by our revolving credit facility, or Revolver, and our internal policies.

Acquisition of Magnum Hunter's Eagle Ford Shale Assets

On April 24, 2013, we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from MHR for approximately $400 million consisting of approximately $360 million in cash and 10 million shares of our common stock, or the Shares. The effective date of the Acquisition was January 1, 2013. The Acquisition includes approximately 40,600 gross (19,000 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired assets also include working interests in 46 gross (22.1 net) producing wells. Estimated net oil and gas production for the acquired assets during 2013 is approximately 2,700 barrels of oil per day equivalent, or BOEPD. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 MMBOE, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.

As a result of the Acquisition, we have approximately 80,200 gross (54,200 net) contiguous acres, the majority of which are in the volatile oil window of the Eagle Ford Shale, approximately 66,900 gross (47,700 net) acres of which are operated by us. Including those acquired in the Acquisition, we currently have a total of 120 gross (84.2 net) Eagle Ford Shale producing wells, with 15 gross (8.8 net) wells either completing or waiting on completion and seven gross (4.1 net) wells being drilled through the first week of May 2013. On a pro forma basis, the Acquisition would have brought our total production to approximately 19,500 BOEPD and our Eagle Ford Shale production in 2013 to approximately 10,900 BOEPD. Our 2013 total production is expected to increase by approximately 3,700 to 4,400 BOEPD for the remainder of 2013, with net capital expenditures expected to increase by approximately $72 to $82 million. We estimate that additional net operating cash flows, prior to interest expense, will be approximately $60 to $70 million during the same period.

Drilling Results and Future Development Plans

During the three months ended March 31, 2013, we drilled nine gross (8.2 net) operated wells in the Eagle Ford Shale all of which were successful. We also drilled one non-operated gross (0.3 net) well in the Granite Wash which is currently under evaluation. Our Eagle Ford Shale production was approximately 7,523 net BOEPD during the three months ended March 31, 2013 with oil comprising approximately 78 percent, NGLs approximately 12 percent and natural gas approximately 10 percent. We have allocated approximately 94 percent of our anticipated capital expenditures during 2013 to activities in the Eagle Ford Shale.

Tender Offer for the 2016 Senior Notes

On April 11, 2013, we initiated the Tender Offer for any and all of the total $300 million principal amount of our 2016 Senior Notes. As of April 24, 2013, holders of approximately 58% of the $300 million total principal amount of the 2016 Senior Notes outstanding had tendered their 2016 Senior Notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered by April 24, 2013 was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. On April 25, 2013, we paid a total of approximately $191 million, including accrued interest of $6.5 million for the 2016 Senior Notes tendered. On May 6, 2013, we made an irrevocable election in connection with the Redemption to redeem on May 10, 2013 the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We will pay a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes in connection with the Redemption. We will recognize a loss on the extinguishment of debt of approximately $29 million in connection with the Tender Offer and the Redemption, which will be recorded in the second quarter of 2013.

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Issuance of 2020 Senior Notes

On April 24, 2013, we completed a private placement of $775 million of our 2020 Senior Notes. The 2020 Senior Notes were priced at par and interest will be payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by all of our material subsidiaries, or Guarantor Subsidiaries. Approximately $380 million of the net proceeds from the private placement, together with the Shares, were used to finance the Acquisition, including purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the revolving credit facility, or the Revolver, and to fund a portion of the Tender Offer and the Redemption.

Commodity Hedging Activities

For the remainder of 2013, we have approximately 65 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $94.38 and $96.58 per barrel. For 2014, we have approximately 35 to 40 percent of our estimated oil production hedged at a weighted-average swap price of $93.27 per barrel. These estimates include our anticipated oil production from the producing properties acquired in the Acquisition as well as properties that are expected to be developed.

For the remainder of 2013, we have approximately 70 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.77 and $4.13 per MMBtu. For 2014, we have approximately 21 percent of our estimated natural gas production hedged at a weighted-average floor/swap and ceiling prices of $4.03 and $4.11 per MMBtu. Similar to oil, these estimates include the Acquisition properties' production and 2013 future development. We do not have any NGLs hedged.

23

Results of Operations

Three Months Ended March 31, 2013 Compared to the Three Months Ended March 31, 2012

Production

The following tables set forth a summary of our total and daily production volumes by product and geographic region for the periods presented: 

Crude oil	Three Months Ended March 31,		Favorable		Three Months Ended March 31,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	529.9	460.1	69.8		5,887.7	5,056.5	831.2		15	%
East Texas	16.6	19.1	(2.5	)	184.4	209.9	(25.5	)	(13	)%
Mid-Continent	48.3	65.1	(16.8	)	536.4	715.1	(178.7	)	(26	)%
Mississippi	4.0	4.0	—		44.9	44.2	0.7		—	%
Appalachia	0.1	0.2	(0.1	)	1.5	2.6	(1.1	)	(43	)%
	598.9	548.6	50.4		6,654.9	6,028.3	626.6		9	%

NGLs	Three Months Ended March 31,		Favorable		Three Months Ended March 31,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	80.0	33.6	46.4		888.7	369.3	0.5		138	%
East Texas	65.1	72.7	(7.6	)	723.6	799.3	(0.1	)	(10	)%
Mid-Continent	89.0	108.3	(19.3	)	988.5	1,189.6	(0.2	)	(18	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	0.2	(0.2	)	—	2.0	—		(100	)%
	234.1	214.8	19.3		2,600.9	2,360.2	240.7		9	%

Natural gas	Three Months Ended March 31,		Favorable		Three Months Ended March 31,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	403	183	220		4.5	2.0	2.5		120	%
East Texas	1,170	1,647	(477	)	13.0	18.1	(5.1	)	(29	)%
Mid-Continent	804	1,108	(304	)	8.9	12.2	(3.2	)	(27	)%
Mississippi	1,151	1,293	(142	)	12.8	14.2	(1.4	)	(11	)%
Appalachia	35	2,062	(2,027	)	0.4	22.7	(22.3	)	(98	)%
	3,565	6,294	(2,729	)	39.6	69.2	(29.6	)	(43	)%

Combined total	Three Months Ended March 31,		Favorable		Three Months Ended March 31,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	677	524	153		7,523.5	5,761.1	1,762.4		29	%
East Texas	277	366	(90	)	3,075.4	4,026.3	(950.9	)	(25	)%
Mid-Continent	271	358	(87	)	3,014.6	3,934.4	(919.8	)	(24	)%
Mississippi	196	220	(24	)	2,176.9	2,413.0	(236.1	)	(11	)%
Appalachia	6	344	(338	)	66.9	3,781.6	(3,714.7	)	(98	)%
	1,427	1,812	(385	)	15,857.3	19,916.4	(4,059.1	)	(21	)%
Certain results in the tables above may not calculate due to rounding.

The decline in total production during the three months ended March 31, 2013 compared to the corresponding period of 2012 was due primarily to the effect of the sale of our Appalachian Basin natural gas properties in July 2012 and production declines in our East Texas and Mid-Continent regions. The effect of the sale of the Appalachian properties was approximately 321 million barrels of oil equivalent, or MBOE. The declines in production from our remaining natural gas properties were partially offset by an increase in oil, NGL and natural gas production attributable to our drilling activity in the Eagle Ford Shale.

24

Approximately 58% of total production during the three months ended March 31, 2013 was attributable to oil and NGLs, which represents an increase of approximately 39% over the prior year period. During the three months ended March 31, 2013, our Eagle Ford Shale production represented approximately 47% of our total production as compared to approximately 29% from this play during the corresponding period during 2012.

Product Revenues and Prices

The following tables set forth a summary of our revenues and prices per unit of volume by product and geographic region for the periods presented:

Crude oil	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
Eagle Ford Shale	$	56,665	$	49,844	$	6,821		$	106.94	$	108.32	$	(1.38	)
East Texas	1,636		1,945		(309		)	98.55		101.83		(3.28		)
Mid-Continent	4,311		6,464		(2,153		)	89.30		99.33		(10.03		)
Mississippi	432		448		(16		)	106.96		111.44		(4.48		)
Appalachia	14		22		(8		)	102.19		91.67		10.52
	$	63,058	$	58,723	$	4,335		$	105.28	$	107.05	$	(1.77	)

NGLs	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
Eagle Ford Shale	$	1,995	$	1,473	$	522		$	24.94	$	43.83	$	(18.89	)
East Texas	1,796		3,302		(1,506		)	27.58		45.40		(17.82		)
Mid-Continent	3,336		4,285		(949		)	37.50		39.58		(2.08		)
Mississippi	—		—		—			—		—		—
Appalachia	—		11		(11		)	—		60.11		(60.11		)
	$	7,127	$	9,071	$	(1,944	)	$	30.45	$	42.24	$	(11.79	)

Natural gas	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Mcfe)
Texas
Eagle Ford Shale	$	1,280	$	422	$	858		$	3.17	$	2.30	$	0.87
East Texas	3,574		3,811		(237		)	3.05		2.31		0.74
Mid-Continent	2,535		1,535		1,000			3.15		1.39		1.76
Mississippi	4,512		3,695		817			3.92		2.86		1.06
Appalachia	138		5,423		(5,285		)	3.91		2.63		1.28
	$	12,039	$	14,886	$	(2,847	)	$	3.38	$	2.37	$	1.01

Combined total	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per BOE)
Texas
Eagle Ford Shale	$	59,940	$	51,739	$	8,201		$	88.52	$	98.69	$	(10.17	)
East Texas	7,006		9,058		(2,052		)	25.31		24.72		0.59
Mid-Continent	10,182		12,284		(2,102		)	37.53		34.31		3.22
Mississippi	4,944		4,143		801			25.23		18.87		6.36
Appalachia	152		5,456		(5,304		)	25.26		15.85		9.41
	$	82,224	$	82,680	$	(456	)	$	57.61	$	45.62	$	11.99

As illustrated below, higher oil and NGL production volume coupled with improved natural gas prices were essentially offset by the overall decline in oil and NGL prices and lower natural gas production volume attributable to the sale of our Appalachian properties. Included in the price variance for natural gas was approximately $0.2 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in the Mid-Continent region.

25

The following table provides an analysis of the change in our revenues for the three months ended March 31, 2013 as compared to the three months ended March 31, 2012:

	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	5,391		$	(1,056	)	$	4,335
NGL	815			(2,759		)	(1,944		)
Natural gas	(6,455		)	3,608			(2,847		)
	$	(249	)	$	(207	)	$	(456	)

Effects of Derivatives

Our oil and gas revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. In the three months ended March 31, 2013 and 2012, we received $3.6 million and $8.0 million, respectively, in cash settlements of oil and gas derivatives.

The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented: 

	Three Months Ended
	March 31,					Favorable
	2013		2012			(Unfavorable)			% Change
Crude oil revenues as reported	$	63,058	$	58,723		$	4,335		7	%
Cash settlements on crude oil derivatives, net	2,809		(107		)	2,916			NM
Crude oil revenues adjusted for derivatives	$	65,867	$	58,616		$	7,251		12	%
Crude oil prices per Bbl, as reported	$	105.28	$	107.05		$	(1.76	)	(2	)%
Cash settlements on crude oil derivatives per Bbl	4.69		(0.20		)	4.89			NM
Crude oil prices per Bbl adjusted for derivatives	$	109.97	$	106.85		$	3.12		3	%
Natural gas revenues as reported	$	12,039	$	14,886		$	(2,847	)	(19	)%
Cash settlements on natural gas derivatives, net	748		8,088			(7,340		)	(91	)%
Natural gas revenues adjusted for derivatives	$	12,787	$	22,974		$	(10,187	)	(44	)%
Natural gas prices per Mcf, as reported	$	3.38	$	2.37		$	1.01		43	%
Cash settlements on natural gas derivatives per Mcf	0.21		1.28			(1.08		)	(84	)%
Natural gas prices per Mcf adjusted for derivatives	$	3.59	$	3.65		$	(0.06	)	(2	)%
NM - Not meaningful

(Loss) Gain on Sales of Property and Equipment

In the three months ended March 31, 2013, we recognized a loss on the assignment of certain properties in West Virginia associated with our 2012 sale of legacy natural gas assets that was not completed until January 2013. In the three months ended March 31, 2012, we recognized a gain attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong Counties, Pennsylvania. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well material during both periods.

Other Income

Other income, which includes ancillary gathering, transportation, compression and water disposal fees and other miscellaneous operating income net of marketing and related expenses, increased during the three months ended March 31, 2013 due primarily to the sale of certain seismic data partially offset by expense attributable to our firm transportation obligation in the Appalachian region.

26

Production and Lifting Costs

	Three Months Ended
	March 31,				Favorable
	2013		2012		(Unfavorable)			% Change
Lease operating	$	7,805	$	9,143	$	1,338		15	%
Per unit of production ($/BOE)	$	5.47	$	5.05	$	(0.42	)	(8	)%

Lease operating expense decreased on an absolute basis during the three months ended March 31, 2013 due primarily to the effect of the sale of our higher-cost Appalachian Basin properties in July 2012. The sale-related cost decreases were more than offset by higher paraffin and corrosion inhibitor chemical costs associated with our increased oil production as well as higher environmental permitting and certain facility and tank battery maintenance costs.

	Three Months Ended
	March 31,				Favorable
	2013		2012		(Unfavorable)			% Change
Gathering, processing and transportation	$	3,579	$	4,154	$	575		14	%
Per unit of production ($/BOE)	$	2.51	$	2.29	$	(0.22	)	(10	)%

Gathering, processing and transportation charges decreased during the three months ended March 31, 2013, due primarily to the effect of the sale of our Appalachian Basin properties in July 2012 partially offset by higher processing costs associated with NGLs in the Eagle Ford Shale in Lavaca County as compared to the corresponding period of 2012.

	Three Months Ended
	March 31,						Favorable
	2013			2012			(Unfavorable)			% Change
Production and ad valorem taxes	$	5,959		$	3,580		$	(2,379	)	(66	)%
Per unit of production ($/BOE)	$	4.18		$	1.98		$	(2.20	)	(111	)%
Tax rate as a percent of product revenue	7.2		%	4.3		%

Production and ad valorem taxes increased during the 2013 period due primarily to our expanding presence in the Eagle Ford Shale in South Texas.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:

	Three Months Ended
	March 31,					Favorable
	2013		2012			(Unfavorable)			% Change
Recurring general and administrative expenses	$	9,844	$	10,457		$	613		6	%
Share-based compensation (liability-classified)	14		72			58			81	%
Share-based compensation (equity-classified)	1,085		1,615			530			33	%
Restructuring expenses	—		(3		)	(3		)	(100	)%
	$	10,943	$	12,141		$	1,198		10	%
Per unit of production ($/BOE)	$	7.67	$	6.70		$	(0.97	)	(14	)%
Per unit of production excluding share-based compensation
and restructuring charges ($/BOE)	$	6.91	$	5.81		$	(1.10	)	(19	)%

Recurring general and administrative expenses decreased due to reduced headcount and lower support costs following the sale of our Appalachian Basin properties in July 2012. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, issued in 2012, which are payable in cash in 2015 upon achievement of specified market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the three months ended March 31, 2013 due primarily to the deferral of 2013 grants to certain officers until approval was received from shareholders on May 1, 2013 for an amendment to our stock compensation plan.

27

Exploration

The following table sets forth the components of exploration expenses for the periods presented:

	Three Months Ended
	March 31,					Favorable
	2013		2012			(Unfavorable)			% Change
Unproved leasehold amortization	$	5,262	$	8,171		$	2,909		36	%
Geological and geophysical costs	980		(423		)	(1,403		)	NM
Other, primarily delay rentals	53		250			197			79	%
	$	6,295	$	7,998		$	1,703		21	%

Unproved leasehold amortization declined during the three months ended March 31, 2013 as costs related to successful Eagle Ford Shale wells were transferred to proved properties. Geological and geophysical costs increased during the 2013 period due primarily to a recoupment from certain of our joint venture partners during the 2012 period of amounts expended in prior periods.

Depreciation, Depletion and Amortization (DD&A)

The following table sets forth the nature of the DD&A variances for the periods presented:

	Three Months Ended
	March 31,					Favorable
	2013		2012			(Unfavorable)			% Change
DD&A expense	$	51,576	$	50,817		$	(759	)	(1	)%
DD&A rate ($/BOE)	$	36.14	$	28.04		$	(8.10	)	(29	)%
	Production		Rates			Total
DD&A variance due to:	$	10,810	$	(11,569	)	$	(759	)

The effect of lower overall production volumes on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average DD&A rate increased due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale.

Interest Expense

The following table summarizes the components of our interest expense for the periods presented:

	Three Months Ended
	March 31,						Favorable
	2013			2012			(Unfavorable)			% Change
Interest on borrowings and related fees	$	13,583		$	14,017		$	434		3	%
Accretion of original issue discount	321			333			12			4	%
Amortization of debt issuance costs	626			682			56			8	%
Capitalized interest	(51		)	(258		)	(207		)	(80	)%
	$	14,479		$	14,774		$	295		2	%
Weighted-average debt outstanding	$	619,678		$	706,739
Weighted average interest rate	9.35		%	8.36		%

Interest expense decreased due primarily to a lower average outstanding principal balance on the Revolver during the three months ended March 31, 2013 despite higher effective interest rates attributable to our fixed rate senior notes. Capitalized interest was lower during the 2013 period due to lower carrying values on eligible capital projects.

28

Derivatives

The following table summarizes the components of our derivatives income for the periods presented:

	Three Months Ended
	March 31,						Favorable
	2013			2012			(Unfavorable)			% Change
Oil and gas derivative realized gain	$	3,557		$	7,981		$	(4,424	)	(55	)%
Oil and gas derivative unrealized loss	(11,318		)	(7,687		)	(3,631		)	(47	)%
Interest rate swap unrealized loss	—			(599		)	599			100	%
	$	(7,761	)	$	(305	)	$	(7,456	)	NM

We received cash settlements of $3.6 million during the three months ended March 31, 2013 and $8.0 million during the three months ended March 31, 2012. The increase in the unrealized loss on commodity derivatives was due primarily to oil and natural gas prices closing at period end above our hedged prices on an aggregate basis.

Other

Other income increased during the three months ended March 31, 2013 due primarily to income earned from a vendor account processing bonus.

Income Taxes

	Three Months Ended
	March 31,						Favorable
	2013			2012			(Unfavorable)		% Change
Income tax benefit	$	8,789		$	6,601		$	2,188	33	%
Effective tax benefit rate	34.9		%	35.7		%

Due to the operating losses incurred, we recognized an income tax benefit during both periods. The effective tax benefit rate for the three months ended March 31, 2013 and 2012 included a deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.

29

 Liquidity and Capital Resources

Sources of Liquidity

Our business strategy contemplates capital expenditures in excess of our projected operating cash flows for 2013. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 2013 capital program with operating cash flows and borrowings under the Revolver. Excluding the 2016 Senior Notes, which will be redeemed in their entirety by May 10, 2013 in connection with the Tender Offer and the Redemption, we have no debt maturities until September 2017 when the Revolver matures.

The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver is governed by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver was $300 million and will be re-determined by the end of May 2013, and semi-annually thereafter, based on a review of our total proved oil, NGL and natural gas reserves. Subsequent to the private placement of the 2020 Senior Notes, our borrowing base under the Revolver was reduced by $23.8 million to $276.2 million. We anticipate the borrowing base will be increased to a level within a range from $320 million to $350 million in connection with the May 2013 re-determination.

As of May 3, 2013, we had $273.4 million of unused borrowing capacity available to us under the Revolver. The borrowing capacity is determined by reducing the current borrowing base of $276.2 million by outstanding letters of credit of $2.8 million. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions.

The following table summarizes our borrowing activity under the Revolver during the period presented:

	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended March 31, 2013	$	23,567	$	38,000	1.7500	%

Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, we actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices and our operating strategy. During the three months ended March 31, 2013, our commodity derivatives portfolio provided $2.8 million of cash inflows related to lower than anticipated prices received for our oil production and $0.7 million of cash inflows attributable to lower than anticipated prices received for our natural gas production.

For the remainder of 2013, we have hedged approximately 65 percent of our estimated crude oil production, at weighted average floor/swap and ceiling prices of between $94.38 and $96.58 per barrel. In addition, we have hedged approximately 70 percent of our estimated natural gas production for 2013, at weighted average floor/swap and ceiling prices of between $3.77 and $4.13 per MMBtu.

30

Cash Flows

The following table summarizes our statements of cash flows for the periods presented:

	Three Months Ended
	March 31,
	2013			2012			Variance
Cash flows from operating activities
Operating cash flows, net	$	42,295		$	42,723		$	(428	)
Working capital changes, net	601			20,351			(19,750		)
Commodity derivative settlements received, net:							—
Crude oil	2,809			(107		)	2,916
Natural gas	748			8,088			(7,340		)
Interest payments, net of amounts capitalized	(340		)	(557		)	217
Income tax refunds received (payments made), net	—			301			(301		)
Restructuring and exit costs paid	(498		)	(98		)	(400		)
Net cash provided by operating activities	45,615			70,701			(25,086		)
Cash flows from investing activities
Capital expenditures -  property and equipment	(85,973		)	(94,469		)	8,496
Proceeds from sales of assets and other, net	878			778			100
Net cash used in investing activities	(85,095		)	(93,691		)	8,596
Cash flows from financing activities
Proceeds from revolving credit facility borrowings, net	38,000			20,000			18,000
Dividends paid on preferred and common stock	(1,687		)	(2,586		)	899
Other, net	(61		)	—			(61		)
Net cash provided by financing activities	36,252			17,414			18,838
Net increase (decrease) in cash and cash equivalents	$	(3,228	)	$	(5,576	)	$	2,348

Cash Flows From Operating Activities

Due primarily to the timing of disbursements and a higher level of accounts payable settled during the 2013 period, our cash flows from operating activities declined during the three months ended March 31, 2013 as compared to the corresponding period during 2012. In addition, we realized lower settlements from our commodity derivatives portfolio during the 2013 period as compared to the corresponding period during 2012 due primarily to a significantly lower volume of natural gas production subject to hedges. Restructuring and exit costs paid were higher during the 2013 period as compared to the corresponding period of 2012 due primarily to ongoing contractual payments for firm transportation capacity in the Appalachian region subsequent to our 2012 sale of assets in that region. Realized cash flows from higher operating margin oil and NGL operations were essentially offset by the absence of natural gas production from the divested Appalachian assets. These decreases in operating cash flows were slightly offset by lower amounts paid for interest during the 2013 period due to lower average outstanding Revolver balances.

Cash Flows From Investing Activities

Capital expenditures were lower during the three months ended March 31, 2013 as compared to the corresponding period during 2012 due primarily to the timing of disbursements and settlements of accrued capital costs attributable to our Eagle Ford Shale drilling program.

Proceeds from sales of non-core properties and other assets were received during both the 2013 and 2012 periods. The amounts received during the 2013 period were attributable primarily to the assignment of certain properties in West Virginia, associated with our 2012 sale of legacy natural gas assets that was not completed until January 2013. The amounts received during the 2012 period were attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong Counties, Pennsylvania.

31

The following table sets forth costs related to our capital expenditure program for the periods presented:

	Three Months Ended
	March 31,
	2013		2012
Oil and gas:
Development drilling	$	75,428	$	61,440
Exploration drilling	11,120		21,152
Geological and geophysical (seismic) costs	980		(423		)
Lease acquisitions	4,997		4,344
Pipeline, gathering facilities and other	2,958		3,901
	95,483		90,414
Other - Corporate	116		66
Total capital program costs	$	95,599	$	90,480

The following table reconciles the total costs of our capital expenditure program with the net cash paid for capital expenditures for additions to property and equipment as reported in our Condensed Consolidated Statements of Cash Flows for the periods presented:

	Three Months Ended
	March 31,
	2013			2012
Total capital program costs	$	95,599		$	90,480
Less:
Exploration expenses
Geological and geophysical (seismic)	(980		)	423
Other, primarily delay rentals	(53		)	(199		)
Transfers from tubular inventory and well materials	(736		)	(6,081		)
Changes in accrued capitalized costs	(7,921		)	9,588
Add:
Tubular inventory and well materials purchased in advance of drilling	13			—
Capitalized interest	51			258
Total cash paid for capital expenditures	$	85,973		$	94,469

Cash Flows From Financing Activities

Cash flows from financing activities for both the three months ended March 31, 2013 and 2012 include borrowings under the Revolver. The 2013 period includes dividends paid on our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock, and the 2012 period includes dividends paid on our common stock.

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Financial Condition

As of May 3, 2013, we had $273.4 million of unused borrowing capacity available to us under the Revolver. The borrowing capacity is determined by reducing the current borrowing base of $276.2 million by outstanding letters of credit of $2.8 million. The indentures for our Senior Notes include an incurrence test which could potentially limit our ability to issue additional debt if our interest coverage ratio, as defined in the indentures, exceeds 2.25 times consolidated EBITDAX, a non-GAAP measure. Our actual interest coverage ratio for the twelve month period ended March 31, 2013 was 3.86.

Debt and Credit Facilities and Preferred Stock Financing

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of May 3, 2013, the actual interest rate applicable to the Revolver was 1.75%.

The Revolver is guaranteed by Penn Virginia and the Guarantor Subsidiaries. The obligations under the Revolver are secured by a first priority lien on substantially all of our proved oil and gas reserves and a pledge of the equity interests in the Guarantor Subsidiaries.

2016 Senior Notes. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes were sold at 97% of par in June 2009, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2019 Senior Notes. The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2020 Senior Notes. The 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on May 1 and November 1 of each year. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

6% Preferred Stock. The annual dividend on each share of the 6% Preferred Stock is 6.00% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each of January 15, April 15, July 15 and October 15 of each year. We may, at our option, pay dividends in cash, common stock or a combination thereof.

Each share of the 6% Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $6.00 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the 6% Preferred Stock. The initial conversion price represents a premium of 20 percent relative to the 2012 common stock offering price of $5.00 per share. The 6% Preferred Stock is not redeemable by us or the holders at any time. At any time on or after October 15, 2017, we may, at our option, cause all outstanding shares of the 6% Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the 6% Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.

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Covenant Compliance

The Revolver requires us to maintain certain financial covenants as follows:

• Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 for periods through December 31, 2013, 4.25 to 1.0 for periods through June 30, 2014 and 4.0 to 1.0 for periods through maturity in 2017. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.

• The current ratio, as of the last day of any quarter, may not be less than 1.0 to 1.0. The current ratio is generally defined as current assets to current liabilities. Current assets and current liabilities attributable to derivative instruments are excluded. In addition, current assets include the amount of any unused commitment under the Revolver.

As of March 31, 2013 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants. The following table summarizes the actual results of our financial covenant compliance under the Revolver as of and for the period ended March 31, 2013:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.5 to 1	2.6 to 1
Current ratio	> 1.0 to 1	2.8 to 1

In the event that we would be in default of a covenant under the Revolver, we could request a waiver of the covenant from our bank group. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the Revolver would become payable on demand and would be reclassified as a component of current liabilities on our Consolidated Balance Sheets. In addition, the Revolver imposes limitations on dividends as well as limits our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.

Future Capital Needs and Commitments

In 2013, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $505 million. The capital expenditures for 2013 will be funded primarily by operating cash flows and borrowings under the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the availability of capital.

Based on expenditures to date and forecasted activity for the remainder of 2013, we expect to allocate capital expenditures as follows: Eagle Ford Shale (approximately 94 percent) and Mid-Continent region and all other areas (approximately 6 percent). This allocation includes approximately 89 percent for drilling and completions, 6 percent for leasehold acquisition and 5 percent for pipeline seismic and other projects. We anticipate that we will allocate substantially all of our capital expenditures to oil and NGL projects.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of March 31, 2013, we have recorded asset retirement obligations of $4.6 million attributable to these activities. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we

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are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012.

New Accounting Standards

During the three months endedMarch 31, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 11 to the Condensed Consolidated Financial Statements. The adoption of ASU 2013-02 did not have a significant impact on our Condensed Consolidated Financial Statements and Notes to the Condensed Consolidated Financial Statements.

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Item 3        Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.

Interest Rate Risk

All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Changes in interest rates do not affect the amount of interest we pay on our fixed-rate debt instruments. However, changes in interest rates will affect the fair value of our long-term debt instruments. Our interest rate risk is attributable to our borrowings under the Revolver, which is subject to variable interest rates. As of March 31, 2013, we had borrowings of $38 million under the Revolver at an interest rate of 1.75%. Assuming a constant borrowing level of $38 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense of approximately $0.4 million on an annual basis.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars, swaps and swaptions) to seek to mitigate the price risks associated with fluctuations in commodity prices as they relate to a portion of our anticipated production. The derivative instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative instruments are significantly affected by fluctuations in the prices of oil and natural gas. We have not typically entered into derivative instruments with respect to NGLs, although we may do so in the future.

As of March 31, 2013, we reported a commodity derivative asset of $9.5 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of March 31, 2013.

During the three months ended March 31, 2013, we reported net commodity derivative losses of $7.8 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment.  See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

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The following table sets forth our commodity derivative positions as of March 31, 2013:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2013	Collars	1,900	$	90.00	$	99.17	$	—	$	164
Third quarter 2013	Collars	1,900	$	90.00	$	99.17	—		235
Fourth quarter 2013	Collars	1,900	$	90.00	$	99.17	—		81
Second quarter 2013	Swaps	3,750	$	101.26			1,460		173
Third quarter 2013	Swaps	4,000	$	98.43			1,038		550
Fourth quarter 2013	Swaps	4,000	$	98.43			1,355		357
First quarter 2014	Swaps	4,000	$	95.27			1,093		720
Second quarter 2014	Swaps	4,000	$	95.27			1,312		519
Third quarter 2014	Swaps	3,500	$	94.43			1,096		347
Fourth quarter 2014	Swaps	3,500	$	94.43			1,199		210
First quarter 2014	Swaption	1,812	$	100.00			—		281
Second quarter 2014	Swaption	1,812	$	100.00			—		280
Third quarter 2014	Swaption	1,812	$	100.00			—		280
Fourth quarter 2014	Swaption	1,812	$	100.00			—		280
Natural Gas:		(in MMBtu)	($/MMBtu)
Second quarter 2013	Collars	10,000	$	3.50	4.30		—		34
Third quarter 2013	Collars	10,000	$	3.50	4.30		—		125
Fourth quarter 2013	Collars	15,000	$	3.67	4.37		15		222
First quarter 2014	Collars	5,000	$	4.00	4.50		—		58
Second quarter 2013	Swaps	15,000	$	3.92			13		151
Third quarter 2013	Swaps	15,000	$	3.92			—		271
Fourth quarter 2013	Swaps	10,000	$	4.04			—		160
First quarter 2014	Swaps	5,000	$	4.05			—		145
Second quarter 2014	Swaps	10,000	$	4.03			—		53
Third quarter 2014	Swaps	10,000	$	4.03			—		105
Settlements to be received in subsequent period							954		—

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil prices, natural gas prices and production volumes remain constant at anticipated levels.  The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

	Change of $10.00 per Bbl of  Crude Oil or $1.00 per MMBtu of Natural Gas ($ in millions)
	Increase			Decrease
Effect on the fair value of crude oil derivatives	$	(33.0	)	$	27.5
Effect on the fair value of natural gas derivatives	$	(8.0	)	$	7.7
Effect on 2013 operating income, excluding crude oil derivatives	$	32.1		$	(32.1	)
Effect on 2013 operating income, excluding natural gas derivatives	$	10.3		$	(10.3	)

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Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 2013. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, 2013, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting that occurred during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II. OTHER INFORMATION

Item 1A Risk Factors

There have been no material changes to the risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012 except for the addition of the following:

We have a significant amount of indebtedness and our ability to service our indebtedness depends on certain financial, business and other factors, many of which are beyond our control.

After giving effect to the Acquisition, the issuance of $775 million of our 2020 Senior Notes and the consummation of the Tender Offer and Redemption, as of March 31, 2013, we would have had approximately $1,075 million of debt outstanding and the ability to incur an additional approximately $273.4 million (net of $2.8 million letters of credit) under the Revolver. The increase in our indebtedness may reduce our flexibility to respond to changing business and economic conditions or to fund capital expenditures or working capital needs.

We and our subsidiaries may incur additional indebtedness in the future. Subject to certain conditions, the terms of our existing debt instruments do not prohibit us or our subsidiaries from incurring additional indebtedness. Any increase in our level of indebtedness may have several important effects on our future operations, including without limitation:

•we will have additional cash requirements in order to support the payment of interest on our outstanding indebtedness;

• increases in our outstanding indebtedness and leverage will increase our vulnerability to adverse changes in general economic and industry condition, as well as to competitive pressure; and

• depending on the levels of our outstanding debt, our ability to obtain additional financing for working capital, capital expenditures, general corporate and other purposes may be limited.

Our ability to make scheduled payments of principal and interest on our indebtedness or to refinance our debt obligations depends on our future financial condition and operating performance, which will be subject to general economic conditions and to certain financial, business and other factors affecting our operations, many of which are beyond our control. If we are unable to generate sufficient cash flows from operations in the future to service our debt, we may be forced, among other things to:

• sell selected assets;

• reduce or delay planned capital expenditures;

• refinance or restructure all or a portion of our indebtedness;

• seek additional financing in the debt or equity markets; or

• reduce or delay planned operating expenditures.

Such measures might not be successful, might not be available on economically favorable terms and might not enable us to service our debt.

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Item 6 Exhibits

(3.1)	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on May 3, 2013).
(4.1)	Senior Indenture, dated June 15, 2009, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2009).
(4.2)	Fourth Supplemental Indenture relating to the 8.500% Senior Notes due 2020, dated April 14, 2013, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
(4.3)	Form of 8.500% Senior Notes due 2020 (incorporated by reference to Exhibit 1 to Exhibit 4.2 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
(4.4)	Registration Rights Agreement, dated April 24, 2013, among Penn Virginia Corporation, the several guarantors named therein and RBC Capital Markets, LLC, as representatives of the initial purchasers named therein (incorporated by reference to Exhibit 4.4 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
(4.5)	Registration Rights, Lock-Up and Buy-Back Agreement, dated April 24, 2013, between Penn Virginia Corporation and Magnum Hunter Resources Corporation (incorporated by reference to Exhibit 4.5 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
(4.6)	Fifth Supplemental Indenture relating to the 10.375% Senior Notes due 2016, dated April 24, 2013, among Penn Virginia Corporation, as issuer, the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.6 to Registrant’s Current Report on Form 8-K filed on April 29, 2013).
(10.1)	Executive Change of Control Severance Agreement dated January 29, 2013 by and between Penn Virginia Corporation and John A. Brooks (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 1, 2013).
(10.2)	Penn Virginia Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K/A filed on February 7, 2013).
(12.1)	Statement of Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Calculation.
(31.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(31.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
(32.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(32.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
(101.INS)	XBRL Instance Document
(101.SCH)	XBRL Taxonomy Extension Schema Document
(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document
(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document
(101.LAB)	XBRL Taxonomy Extension Label Linkbase Document
(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document

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SIGNATURES

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

	PENN VIRGINIA CORPORATION
	By:	/s/ STEVEN A. HARTMAN
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer
May 8, 2013	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President and Controller

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