PVA-2014.03.31-10Q

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 ¨



Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended March 31, 2014 and 2013	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended March 31, 2014 and 2013	4
	Condensed Consolidated Balance Sheets as of March 31, 2014 and December 31, 2013	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 2014 and 2013	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Acquisitions and Divestitures	7
	4. Accounts Receivable and Major Customers	9
	5. Derivative Instruments	9
	6. Property and Equipment	12
	7. Long-Term Debt	12
	8. Income Taxes	13
	9. Additional Balance Sheet Detail	13
	10. Fair Value Measurements	15
	11. Commitments and Contingencies	16
	12. Shareholders' Equity	17
	13. Share-Based Compensation	17
	14. Restructuring and Exit Activities	18
	15. Interest Expense	18
	16. Earnings per Share	19
Forward-Looking Statements		20
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	21
	Key Developments	22
	Results of Operations	23
	Financial Condition	29
	Critical Accounting Estimates	33
3.	Quantitative and Qualitative Disclosures About Market Risk	34
4.	Controls and Procedures	36
Part II - Other Information
1.	Legal Proceedings	37
6.	Exhibits	37
Signatures		38



	Three Months Ended
	March 31,
	2014			2013
Revenues
Crude oil	$	105,576		$	63,058
Natural gas liquids (NGLs)	9,373			7,127
Natural gas	18,203			12,039
Gain (loss) on sales of property and equipment, net	56,826			(549		)
Other, net	(113		)	1,523
Total revenues	189,865			83,198
Operating expenses
Lease operating	10,404			7,805
Gathering, processing and transportation	2,961			3,579
Production and ad valorem taxes	7,305			5,959
General and administrative	16,688			10,943
Exploration	8,636			6,295
Depreciation, depletion and amortization	72,187			51,576
Total operating expenses	118,181			86,157
Operating income (loss)	71,684			(2,959		)
Other income (expense)
Interest expense	(22,534		)	(14,479		)
Derivatives	(15,662		)	(7,761		)
Other	1			27
Income (loss) before income taxes	33,489			(25,172		)
Income tax (expense) benefit	(14,264		)	8,789
Net income (loss)	19,225			(16,383		)
Preferred stock dividends	(1,722		)	(1,725		)
Net income (loss) attributable to common shareholders	$	17,503		$	(18,108	)
Net income (loss) per share:
Basic	$	0.27		$	(0.33	)
Diluted	$	0.22		$	(0.33	)

Weighted average shares outstanding - basic	65,611			55,341
Weighted average shares outstanding - diluted	85,744			55,341



	As of
	March 31,			December 31,
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	9,554		$	23,474
Accounts receivable, net of allowance for doubtful accounts	167,190			194,403
Derivative assets	65			3,830
Deferred income taxes	6,065			6,065
Other current assets	5,372			5,924
Total current assets	188,246			233,696
Property and equipment, net (successful efforts method)	2,312,003			2,237,304
Derivative assets	1,974			1,552
Other assets	33,710			34,535
Total assets	$	2,535,933		$	2,507,087

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	238,212		$	248,004
Derivative liabilities	19,403			10,141
Income taxes payable	200			—
Total current liabilities	257,815			258,145
Other liabilities	45,045			33,386
Deferred income taxes	159,830			145,752
Long-term debt	1,265,000			1,281,000

Commitments and contingencies (Note 11)

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; 11,481 and 11,500 shares issued as of March 31, 2014 and December 31, 2013, respectively, with a redemption value of $10,000 per share	1,148			1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 65,581,512 and 65,306,748 shares issued as of March 31, 2014 and December 31, 2013, respectively	468			466
Paid-in capital	893,262			891,351
Accumulated deficit	(86,677		)	(104,180		)
Deferred compensation obligation	2,897			2,792
Accumulated other comprehensive income	292			267
Treasury stock – 239,065 and 233,063 shares of common stock, at cost, as of March 31, 2014 and December 31, 2013, respectively	(3,147		)	(3,042		)
Total shareholders’ equity	808,243			788,804
Total liabilities and shareholders’ equity	$	2,535,933		$	2,507,087



	Three Months Ended
	March 31,
	2014			2013
Cash flows from operating activities
Net income (loss)	$	19,225		$	(16,383	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	72,187			51,576
Accretion of firm transportation obligation	354			207
Derivative contracts:
Net losses	15,662			7,761
Cash settlements, net	(3,057		)	3,557
Deferred income tax expense (benefit)	14,064			(8,789		)
(Gain) loss on sales of assets, net	(56,826		)	549
Non-cash exploration expense	3,294			5,262
Non-cash interest expense	1,012			946
Share-based compensation (equity-classified)	825			1,085
Other, net	206			81
Changes in operating assets and liabilities	(386		)	(237		)
Net cash provided by operating activities	66,560			45,615

Cash flows from investing activities
Capital expenditures - property and equipment	(159,804		)	(85,973		)
Proceeds from sales of assets, net	95,964			878
Net cash used in investing activities	(63,840		)	(85,095		)

Cash flows from financing activities
Proceeds from revolving credit facility borrowings	85,000			38,000
Repayment of revolving credit facility borrowings	(101,000		)	—
Dividends paid on preferred stock	(1,725		)	(1,687		)
Other, net	1,085			(61		)
Net cash (used in) provided by financing activities	(16,640		)	36,252
Net decrease in cash and cash equivalents	(13,920		)	(3,228		)
Cash and cash equivalents - beginning of period	23,474			17,650
Cash and cash equivalents - end of period	$	9,554		$	14,422

Supplemental disclosures:
Cash paid for:
Interest	$	1,025		$	340
Income taxes (net of refunds received)	$	—		$	—

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas in various onshore regions of the United States. Our current operations consist primarily of the drilling of unconventional horizontal development wells in shale formations and are currently concentrated in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma, the Haynesville Shale and Cotton Valley in East Texas and the Selma Chalk in Mississippi.

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, 2013. Operating results for the three months ended March 31, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014. Certain amounts for the 2013 period have been reclassified to conform to the current year presentation.

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

On April 24, 2013 (the “Acquisition Date”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play (the “EF Acquisition”). The EF Acquisition was originally valued at $401 million with an effective date of January 1, 2013 (the “Effective Date”). On the Acquisition Date we paid approximately $380 million in cash, including approximately $19 million of initial purchase price adjustments related to the period from the Effective Date to the closing, and issued to the seller 10 million shares of our common stock (the “Shares”) with a fair value of $4.23 per share. Shortly after the closing, certain of our joint interest partners exercised preferential rights related to the EF Acquisition. We received approximately $21 million from the exercise of these rights, which was recorded as a decrease to our purchase price for the EF Acquisition.

Since December 2013, we have been involved in an arbitration with Magnum Hunter Resources Corporation (“MHR”), the seller in our EF Acquisition. The arbitration relates to disputes we have with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believe MHR is obligated to transfer to us. MHR has indicated that it owes us approximately $26.5 million; we believe the amount is higher. Both parties submitted rebuttals to initial briefs on March 3, 2014 and submitted additional responses and replies on April 4, 2014. We expect the arbitration to be resolved in the second quarter of 2014.

We accounted for the EF Acquisition by applying the acquisition method of accounting as of the Acquisition Date. The initial accounting for the EF Acquisition as presented below is based upon preliminary information and was not complete, due primarily to the aforementioned arbitration, as of the date our Condensed Consolidated Financial Statements were issued.



Assets
Oil and gas properties - proved	$	277,888
Oil and gas properties - unproved	119,709
Accounts receivable, net	97,145
Other assets	2,068
	496,810
Liabilities
Accounts payable and accrued expenses	94,771
Other liabilities	1,500
	96,271
Net assets acquired	$	400,539

Cash, net of amounts received for preferential rights	$	358,239
Fair value of the Shares issued to MHR	42,300
Consideration paid	$	400,539

The fair values of the acquired net assets 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) 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 EF Acquisition have been included in our Condensed Consolidated Financial Statements from the Acquisition Date. The following table presents unaudited summary pro forma financial information for the period presented assuming the EF Acquisition and the related financing 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 EF Acquisition had occurred as of this date or the results of operations for any future periods.

In December 2013, we entered into an agreement to sell our natural gas gathering assets in South Texas. Concurrent with the sale, we entered into a long-term agreement in which the buyer will provide us natural gas gathering and compression services for a substantial portion of our natural gas and NGL production in the South Texas region. The transaction closed in January 2014 and resulted in the receipt of proceeds of approximately $96 million. We realized a gain of $67.3 million of which $56.7 million was recognized at the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period. We amortized $0.1 million of the deferred gain during the three months ended March 31, 2014. As of March 31, 2014, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $10.1 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

For the three months ended March 31, 2014, four customers accounted for $89.5 million, or approximately 67%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2014 were $38.8 million, $17.4 million, $17.2 million and $16.1 million or 29%, 13%, 13% and 12% of the consolidated total, respectively. As of March 31, 2014, $40.0 million, or approximately 43% of our consolidated accounts receivable from customers was related to these customers. 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 approximately 20%, 13%, 13% and 10% of the consolidated total, respectively. As of December 31, 2013, $36.9 million, or approximately 40% of our consolidated accounts receivable from customers, was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.

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.



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2014	Collars	2,500	$	92.00	$	99.46	$	—	$	740
Third quarter 2014	Collars	2,000	$	90.00	94.33		—		827
Fourth quarter 2014	Collars	2,000	$	90.00	94.33		—		420
First quarter 2015	Collars	4,000	$	87.50	94.66		—		278
Second quarter 2015	Collars	4,000	$	87.50	94.66		276		—
Third quarter 2015	Collars	3,000	$	86.67	94.73		507		—
Fourth quarter 2015	Collars	3,000	$	86.67	94.73		766		—
Second quarter 2014	Swaps	8,500	$	94.00			—		4,984
Third quarter 2014	Swaps	10,000	$	93.21			342		4,410
Fourth quarter 2014	Swaps	10,000	$	93.21			709		2,417
First quarter 2015	Swaps	7,000	$	90.79			—		1,440
Second quarter 2015	Swaps	7,000	$	90.79			—		447
Third quarter 2015	Swaps	6,000	$	90.45			150		—
Fourth quarter 2015	Swaps	6,000	$	90.45			722		—
First quarter 2015	Swaptions	1,000	$	88.00			—		535
Second quarter 2015	Swaptions	1,000	$	88.00			—		534
Third quarter 2015	Swaptions	1,000	$	88.00			—		534
Fourth quarter 2015	Swaptions	1,000	$	88.00			—		534

Natural Gas:		(in MMBtu)	($/MMBtu)
Second quarter 2014	Swaps	15,000	$	4.10			—		474
Third quarter 2014	Swaps	15,000	$	4.10			—		450
Fourth quarter 2014	Swaps	5,000	$	4.50			—		2
First quarter 2015	Swaps	5,000	$	4.50			—		49
Settlements to be paid in subsequent period							—		1,761



	Three Months Ended
	March 31,
	2014			2013
Impact by contract type:
Commodity contracts	$	(15,662	)	$	(7,761	)
Interest rate contracts	—			—
	$	(15,662	)	$	(7,761	)
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	(3,057	)	$	3,557
Interest rate contract settlements	—			—
	(3,057		)	3,557
Losses attributable to:
Commodity contracts	(12,605		)	(11,318		)
Interest rate contracts	—			—
	(12,605		)	(11,318		)
	$	(15,662	)	$	(7,761	)

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



		Fair Values as of
		March 31, 2014				December 31, 2013
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	65	$	19,403	$	3,830	$	10,141
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		65		19,403		3,830		10,141

Commodity contracts	Derivative assets/liabilities - noncurrent	1,974		—		1,552		—
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		1,974		—		1,552		—
		$	2,039	$	19,403	$	5,382	$	10,141

As of March 31, 2014, we reported a commodity derivative asset of $2.0 million. The contracts associated with this position are with five 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 neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.



	As of
	March 31,			December 31,
	2014			2013
Oil and gas properties:
Proved	$	462,404		$	460,255
Unproved	101,426			101,520
Total oil and gas properties	563,830			561,775
Other property and equipment:
Wells equipment and facilities	2,738,102			2,593,700
Support equipment	21,857			21,513
Total other property and equipment	2,759,959			2,615,213
	3,323,789			3,176,988
Accumulated depreciation, depletion and amortization	(1,011,786		)	(939,684		)
	$	2,312,003		$	2,237,304

The revolving credit facility (the “Revolver”) provides for a $400 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $200 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, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. In May 2014, the borrowing base was increased from $425 million to $475 million, due primarily to our continued development in the Eagle Ford Shale. The next semi-annual redetermination is scheduled for November 2014. 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 $1.7 million outstanding as of March 31, 2014. As of March 31, 2014, our available borrowing capacity under the Revolver was $208.3 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. As of March 31, 2014, the actual interest rate on the outstanding borrowings under the Revolver was 1.9375% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. 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, 2014, commitment fees were being charged at a rate of 0.375%.

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 June 30, 2014, 4.25 to 1.0 through December 31, 2014 and then 4.0 to 1.0 through maturity.

The 7.25% Senior Notes due 2019 (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 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.

The 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on June 15 and December 15 of each year. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are 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.

The guarantees provided by Penn Virginia, which is the parent company, and the Guarantor Subsidiaries under the Revolver and the senior indebtedness described above 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.

We recognized income tax expense for the three months ended March 31, 2014 at an effective tax rate of 42.6%. The effective tax rate reflects the adverse effect of losses incurred in certain jurisdictions for which we may not realize a tax benefit and have therefore recorded a valuation allowance against the related deferred tax assets. Such losses reduce our taxable income without a corresponding reduction in our income tax expense, and therefore increase our effective tax rate. Additionally, our effective tax rate is also adversely impacted by the amount of losses in certain subsidiaries relative to taxable income of the Company. Due to the loss incurred during the three months ended March 31, 2013, we recognized an income tax benefit at an effective tax rate of 34.9%. The income tax benefit included the effect of deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.



	As of
	March 31,		December 31,
	2014		2013
Other current assets:
Tubular inventory and well materials	$	1,965	$	2,271
Prepaid expenses	3,407		3,653
	$	5,372	$	5,924
Other assets:
Debt issuance costs	$	29,227	$	30,239
Assets of supplemental employee retirement plan (“SERP”)	3,815		3,734
Other	668		562
	$	33,710	$	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	$	75,235	$	120,278
Drilling and other lease operating costs	62,620		51,529
Royalties	41,860		39,929
Production and franchise taxes	1,929		5,338
Compensation - related	7,951		8,584
Interest	37,833		15,718
Preferred stock dividends	1,722		1,725
Other	9,062		4,903
	$	238,212	$	248,004
Other liabilities:
Deferred gain on sale of assets	$	10,095	$	—
Firm transportation obligation	12,964		13,245
Asset retirement obligations (“AROs”)	6,537		6,437
Defined benefit pension obligations	1,523		1,579
Postretirement health care benefit obligations	1,071		1,023
Deferred compensation - SERP obligations and other	4,089		3,883
Other	8,766		7,219
	$	45,045	$	33,386

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.



	As of March 31, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	65		$	—		$	65		$	—
Commodity derivative assets - noncurrent	1,974			—			1,974			—
Assets of SERP	3,815			3,815			—			—
Liabilities:
Commodity derivative liabilities - current	(19,403		)	—			(19,403		)	—
Commodity derivative liabilities - noncurrent	—			—			—			—
Deferred compensation - SERP obligations	(4,084		)	(4,084		)	—			—



	As of December 31, 2013
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	3,830		$	—		$	3,830		$	—
Commodity derivative assets - noncurrent	1,552			—			1,552			—
Assets of SERP	3,734			3,734			—			—
Liabilities:
Commodity derivative liabilities - noncurrent	(10,141		)	—			(10,141		)	—
Deferred compensation - SERP obligations	(3,879		)	(3,879		)	—			—

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, 2014 and 2013.

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of net assets acquired, the recognition and measurement of asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes of recognizing and measuring net assets acquired and asset impairments 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 estimates as level 3 inputs.

We have agreements to purchase oil and gas well drilling and well completion services from third parties with remaining terms of up to 14 months. 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. As of March 31, 2014, the penalty amount would have been $17.3 million if we had terminated our agreements on that date.

We have entered into contracts that provide firm transportation capacity rights for specified volumes per day on various pipeline systems with terms that range from 1 to 15 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion.

As discussed in Note 3, we entered into a long-term agreement that provides natural gas gathering and compression services for a substantial portion of our natural gas and NGL production in the South Texas region through 2038. The agreement requires us to make certain minimum fee payments regardless of the volume of natural gas and NGL production for the first three years of the term. The minimum fee requirements for 2014 through 2016 are $3.7 million, $4.2 million and $5.0 million, respectively.

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, 2014. 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 discussed in Note 3, we are involved in an arbitration with MHR in connection with our EF Acquisition. As of March 31, 2014, we also have AROs of approximately $6.5 million attributable to the plugging of abandoned wells.



	As of												As of
	December 31,						Dividends			All Other			March 31,
	2013			Net Loss			Declared ¹			Changes ²			2014
Preferred stock ³	$	1,150		$	—		$	—		$	(2	)	$	1,148
Common stock ³	466			—			—			2			468
Paid-in capital ³	891,351			—			—			1,911			893,262
Retained earnings	(104,180		)	19,225			(1,722		)	—			(86,677		)
Deferred compensation obligation	2,792			—			—			105			2,897
Accumulated other comprehensive income ⁴	267			—			—			25			292
Treasury stock	(3,042		)	—			—			(105		)	(3,147		)
	$	788,804		$	19,225		$	(1,722	)	$	1,936		$	808,243

	As of												As of
	December 31,						Dividends			All Other			March 31,
	2012			Net Loss			Declared ¹			Changes ²			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 ⁴	(982		)	—			—			19			(963		)
Treasury stock	(3,363		)	—			—			(64		)	(3,427		)
	$	895,116		$	(16,383	)	$	(1,725	)	$	685		$	877,693

⁴ The Accumulated other comprehensive income (loss) (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the three months ended March 31, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $38 and $29 and are presented above net of taxes of $13 and $10.

The Penn Virginia Corporation 2013 Amended and Restated Long-Term Incentive Plan (the “LTI Plan”) permits 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 LTI Plan in the General and administrative caption on our Condensed Consolidated Statements of Operations.

With the exception of performance-based restricted stock units (“PBRSUs”), all of the awards issued under our LTI Plan 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 Accounts payable and accrued liabilities (current portion) and Other liabilities (noncurrent portion) captions 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.

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 of our natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production to satisfy this commitment. 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 our obligations as well as the recognition of accretion expense and adjustments associated with changes in estimates.

The current portion of our restructuring and exit cost obligations is included in the Accounts payable and accrued liabilities caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of March 31, 2014, $2.7 million of the total obligations are classified as current while the remaining $13.1 million are classified as noncurrent.



	Three Months Ended
	March 31,
	2014			2013
Net income (loss)	$	19,225		$	(16,383	)
Less: Preferred stock dividends	(1,722		)	(1,725		)
Net income (loss) attributable to common shareholders - Basic	17,503			(18,108		)
Add: Preferred stock dividends	1,722			—
Net income (loss) attributable to common shareholders - Diluted	$	19,225		$	(18,108	)

Weighted-average shares - Basic	65,611			55,341
Effect of dilutive securities ¹	20,133			—
Weighted-average shares - Diluted	85,744			55,341

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:

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.

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” the “Company,” “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. Certain year-over-year changes are presented as not meaningful, or “NM,” where disclosure of the actual value does not otherwise enhance the analysis. Also, due to the combination of different units of volumetric measure and the number of decimal places presented, certain results may not calculate explicitly from the values presented in the tables.

We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various onshore regions of the United States. Our current operations consist primarily of the drilling of unconventional horizontal development wells in shale formations and are currently concentrated in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma, the Haynesville Shale and Cotton Valley in East Texas and the Selma Chalk in Mississippi. As of December 31, 2013, we had proved oil and gas reserves of approximately 136 million barrels of oil equivalent, or MMBOE.



	Three Months Ended
	March 31,
	2014			2013
Total production (MBOE)	1,902			1,427
Daily production (BOEPD)	21,133			15,857
Crude oil and NGL production (MBbl)	1,303.0			833.0
Crude oil and NGL production as a percent of total	69		%	58		%
Product revenues, as reported	$	133,152		$	82,224
Product revenues, as adjusted for derivatives	$	130,095		$	85,781
Crude oil and NGL revenues as a percent of total, as reported	86		%	85		%
Realized prices:
Crude oil ($/Bbl)	$	98.12		$	105.28
NGL ($/Bbl)	$	41.27		$	30.45
Natural gas ($/Mcf)	$	5.07		$	3.38
Aggregate ($/BOE)	$	70.01		$	57.61
Production and lifting costs ($/BOE):
Lease operating	$	5.47		$	5.47
Gathering, processing and transportation	1.56			2.51
Production and ad valorem taxes ($/BOE)	3.84			4.18
General and administrative ($/BOE) ¹	8.33			6.91
Total operating costs ($/BOE)	$	19.20		$	19.07
Depreciation, depletion and amortization ($/BOE)	$	37.95		$	36.14
Cash provided by operating activities	$	66,560		$	45,615
Cash paid for capital expenditures	$	159,804		$	85,973
Cash and cash equivalents at end of period	$	9,554		$	14,422
Debt outstanding, net of discounts, at end of period	$	1,265,000		$	633,080
Credit available under revolving credit facility at end of period ²	$	208,346		$	259,222
Net development wells drilled	13.8			8.5
Net exploratory wells drilled	—			—

_______________________

In the three months ended March 31, 2014, our crude oil and NGL production increased to 69 percent of our total production continuing a trend consistent with our liquids-focused strategy. Our cash margin, or aggregate realized prices less total operating costs excluding equity-classified share-based compensation, increased $12.27 per barrel of oil equivalent, or BOE, or 32 percent to $50.81 per BOE for the three months ended March 31, 2014 from $38.54 per BOE for the corresponding period in 2013. The cash margin increased $3.74 per BOE, or 8 percent, when compared to $47.07 per BOE for the three months ended December 31, 2013. The higher cash margins are attributable primarily to higher liquids production and higher natural gas prices compared to the fourth quarter of 2013 and the corresponding period of the prior year. Consistent with our growth in cash margins, our cash from operating activities increased $20.9 million, or 46 percent, to $66.5 million for the three months ended March 31, 2014 from $45.6 million during the corresponding period of the prior year.

Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford Shale in South Texas. Since our initial acquisition in this region in 2010, we have drilled and turned in line 198 gross (130.7 net) wells through March 31, 2014. We are currently operating a total of six drilling rigs in the Eagle Ford Shale. Our capital program, of which approximately 98 percent is dedicated to the Eagle Ford Shale, is being financed with a combination of cash from operating activities, the sale of non-core assets and borrowings under our revolving credit facility, or the Revolver. During the three months ended March 31, 2014, our cash on hand and cash from operating activities together with the net proceeds received from the sale of our natural gas gathering assets in South Texas were sufficient to fund our capital spending and provided for a net repayment of borrowings under the Revolver in the amount of $16 million.

The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) drilling results and future development plans in the Eagle Ford Shale, (ii) the sale of non-core assets and (iii) arbitration developments related to our Eagle Ford Shale acquisition in 2013.

During the three months ended March 31, 2014, we completed 16 gross (12.9 net) operated wells and participated in the completion of two (0.9 net) outside operated wells in the Eagle Ford Shale. Our Eagle Ford Shale production was 14,752 net barrels of oil equivalent per day, or BOEPD, during the three months ended March 31, 2014 with oil comprising 11,512 BOPD, or 78 percent, NGLs approximately 11 percent and natural gas approximately 11 percent. Our Eagle Ford Shale oil production was seven percent higher than 10,759 BOPD in the fourth quarter of 2013. In the Eagle Ford Shale, we have a total of 198 gross (130.7 net) producing wells, 19 gross (11.1 net) operated wells completing or waiting on completion and six gross (3.4 net) operated wells being drilled as of March 31, 2014. We have approximately 125,300 gross (85,900 net) acres as of May 2, 2014, which to a large extent are contiguous and the vast majority of which are in the “volatile oil window” of the Eagle Ford Shale.

In December 2013, we entered into an agreement to sell our natural gas gathering assets in South Texas. Concurrent with the sale, we entered into a long-term agreement in which the buyer will provide us natural gas gathering and compression services for a substantial portion of our natural gas and NGL production in the South Texas region. The transaction closed in January 2014 and resulting in net proceeds of approximately $96 million. We realized a gain of $67.3 million of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period. We amortized $0.1 million of the deferred gain during the three months ended March 31, 2014.

Since December 2013, we have been involved in an arbitration with Magnum Hunter Resources Corporation, or MHR, the seller in our 2013 property acquisition in the Eagle Ford Shale, or EF Acquisition. The arbitration relates to disputes we have with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believe MHR is obligated to transfer to us. MHR has indicated that it owes us approximately $26.5 million; we believe the amount is higher. Both parties submitted rebuttals to initial briefs on March 3, 2014 and submitted additional responses and replies on April 4, 2014. We expect the arbitration to be resolved in the second quarter of 2014.



Crude oil	Three Months Ended				Three Months Ended
	March 31,		Favorable		March 31,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	1,036.1	529.9	506.2		11,511.7	5,887.7	5,624.0		96	%
East Texas	12.8	16.6	(3.8	)	142.3	184.4	(42.1	)	(23	)%
Mid-Continent	24.5	48.3	(23.8	)	271.9	536.4	(264.5	)	(49	)%
Mississippi	2.6	4.0	(1.4	)	29.0	44.9	(15.8	)	(35	)%
Appalachia	—	0.1	(0.1	)	—	1.5	(1.5	)	(100	)%
	1,075.9	598.9	477.0		11,955.0	6,654.9	5,300.0		80	%



NGLs	Three Months Ended				Three Months Ended
	March 31,		Favorable		March 31,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	151.4	80.0	71.4		1,682.4	888.7	793.7		89	%
East Texas	24.4	65.1	(40.7	)	271.2	723.6	(452.5	)	(63	)%
Mid-Continent	51.3	89.0	(37.7	)	569.7	988.5	(418.8	)	(42	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	—	—		—	—	—		—	%
	227.1	234.1	(7.0	)	2,523.2	2,600.9	(77.6	)	(3	)%



Natural gas	Three Months Ended				Three Months Ended
	March 31,		Favorable		March 31,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	846	403	443		9.4	4.5	4.9		110	%
East Texas	1,070	1,170	(101	)	11.9	13.0	(1.1	)	(9	)%
Mid-Continent	588	804	(216	)	6.5	8.9	(2.4	)	(27	)%
Mississippi	1,054	1,151	(98	)	11.7	12.8	(1.1	)	(8	)%
Appalachia	36	35	1		0.4	0.4	—		2	%
	3,593	3,565	29		39.9	39.6	0.3		1	%



Combined total	Three Months Ended				Three Months Ended
	March 31,		Favorable		March 31,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	1,329	677	651		14,761.3	7,523.5	7,237.8		96	%
East Texas	215	277	(61	)	2,394.1	3,075.4	(681.3	)	(22	)%
Mid-Continent	174	271	(98	)	1,930.7	3,014.6	(1,083.9	)	(36	)%
Mississippi	178	196	(18	)	1,980.1	2,176.9	(196.8	)	(9	)%
Appalachia	6	6	—		66.4	66.9	(0.5	)	(1	)%
	1,902	1,427	475		21,132.6	15,857.2	5,275.4		33	%

Total production increased during the three months ended March 31, 2014 compared to the corresponding period of 2013 due primarily to production from the properties acquired and developed from the EF Acquisition and the continued expansion of our legacy development program in South Texas, both of which are concentrated in the Eagle Ford Shale. The increase was partially offset by natural production declines in our East Texas, Mid-Continent and Mississippi regions. Approximately 69% of total production during the three months ended March 31, 2014 was attributable to oil and NGLs, which represents an increase



Crude oil	Three Months Ended							Three Months Ended
	March 31,				Favorable			March 31,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	101,767	$	56,665	$	45,102		$	98.23	$	106.94	$	(8.71	)
East Texas	1,253		1,636		(383		)	97.82		98.55		(0.73		)
Mid-Continent	2,308		4,311		(2,003		)	94.31		89.30		5.01
Mississippi	248		432		(184		)	94.91		106.96		(12.05		)
Appalachia	—		14		(14		)	—		102.19		NM
	$	105,576	$	63,058	$	42,518		$	98.12	$	105.28	$	(7.16	)



NGLs	Three Months Ended							Three Months Ended
	March 31,				Favorable			March 31,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	4,815	$	1,995	$	2,820		$	31.80	$	24.94	$	6.86
East Texas	1,513		1,796		(283		)	62.00		27.58		34.42
Mid-Continent	3,045		3,336		(291		)	59.39		37.50		21.89
Mississippi	—		—		—			—		—		—
Appalachia	—		—		—			—		—		—
	$	9,373	$	7,127	$	2,246		$	41.27	$	30.44	$	10.83



Natural gas	Three Months Ended						Three Months Ended
	March 31,				Favorable		March 31,				Favorable
	2014		2013		(Unfavorable)		2014		2013		(Unfavorable)
							($ per Mcfe)
Texas
South Texas	$	3,813	$	1,280	$	2,533	$	4.51	$	3.17	$	1.33
East Texas	5,915		3,574		2,341		5.53		3.05		2.48
Mid-Continent	3,111		2,535		576		5.29		3.15		2.14
Mississippi	5,186		4,512		674		4.92		3.92		1.00
Appalachia	178		138		40		4.96		3.91		1.05
	$	18,203	$	12,039	$	6,164	$	5.07	$	3.38	$	1.69



Combined total	Three Months Ended							Three Months Ended
	March 31,				Favorable			March 31,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per BOE)
Texas
South Texas	$	110,395	$	59,940	$	50,455		$	83.10	$	88.52	$	(5.43	)
East Texas	8,681		7,006		1,675			40.29		25.31		14.98
Mid-Continent	8,464		10,182		(1,718		)	48.71		37.53		11.18
Mississippi	5,434		4,944		490			30.49		25.23		5.26
Appalachia	178		152		26			29.79		25.26		4.53
	$	133,152	$	82,224	$	50,928		$	70.01	$	57.61	$	12.39

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, 2014 and 2013, we paid $3.1 million and received $3.6 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
	2014			2013		(Unfavorable)			% Change
Crude oil revenues as reported	$	105,576		$	63,058	$	42,518		67	%
Cash settlements on crude oil derivatives, net	(2,278		)	2,809		(5,087		)	NM
	$	103,298		$	65,867	$	37,431		57	%

Crude oil prices per Bbl, as reported	$	98.12		$	105.28	$	(7.16	)	(7	)%
Cash settlements on crude oil derivatives per Bbl	(2.12		)	4.69		(6.80		)	NM
	$	96.00		$	109.97	$	(13.96	)	(13	)%

Natural gas revenues as reported	$	18,203		$	12,039	$	6,164		51	%
Cash settlements on natural gas derivatives, net	(779		)	748		(1,527		)	(204	)%
	$	17,424		$	12,787	$	4,637		36	%

Natural gas prices per Mcf, as reported	$	5.07		$	3.38	$	1.69		50	%
Cash settlements on natural gas derivatives per Mcf	(0.22		)	0.21		(0.43		)	(205	)%
	$	4.85		$	3.59	$	1.26		35	%

In the three months ended March 31, 2014, we recognized a gain of $56.8 million in connection with the sale of our gathering assets in South Texas, including $56.7 million recognized upon the closing of the sale and $0.1 million attributable to the amortization of the deferred portion of the gain. In the three months ended March 31, 2013, we recognized a loss related to certain properties in West Virginia associated with our 2012 sale of Appalachian natural gas assets.

Other income, which includes gathering, transportation, compression and water disposal fees and other miscellaneous operating income, net of marketing and related expenses, decreased during the three months ended March 31, 2014 due primarily to a $1.6 million gain on the sale of certain proprietary seismic data during the 2013 period as well as higher accretion expense in the 2014 period attributable to our unused firm transportation obligation in the Appalachian region.

gas gathering assets in the South Texas region and entered into an agreement with the buyer to provide us natural gas gathering and compression services. We began incurring costs for these services in February 2014. The corresponding period of the prior year does not include comparable costs as we owned and operated these assets through January 2014. We also incurred higher downhole maintenance costs, particularly in our East Texas region, during the three months ended March 31, 2014. These increases were offset partially by lower equipment repairs and lower chemical and environmental compliance costs.

Gathering, processing and transportation charges decreased during the three months ended March 31, 2014, due primarily to lower natural gas and NGL production volume in our East Texas, Mid-Continent and Mississippi regions. The decrease was offset partially by gathering charges for natural gas and NGL production in the South Texas region attributable to the new gathering and compression services agreement discussed above. Consistent with the discussion of compression charges above, the corresponding period of 2013 does not include similar gathering charges because we owned these assets.



	Three Months Ended
	March 31,						Favorable
	2014			2013			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	6,370		$	4,063		$	(2,307	)	(57	)%
Ad valorem taxes	935			1,896			961			51	%
	$	7,305		$	5,959		$	(1,346	)	(23	)%
Per unit production ($/BOE)	$	3.84		$	4.18		$	0.34		8	%
Production/severance tax rate as a percent of product revenue	4.8		%	4.9		%

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



	Three Months Ended
	March 31,				Favorable
	2014		2013		(Unfavorable)			% Change
General and administrative expenses	$	9,906	$	9,844	$	(62	)	(1	)%
Share-based compensation (liability-classified)	5,945		14		(5,931		)	NM
Share-based compensation (equity-classified)	825		1,085		260			24	%
Restructuring expenses	12		—		(12		)	NM
	$	16,688	$	10,943	$	(5,745	)	(52	)%
Per unit of production ($/BOE)	$	8.77	$	7.67	$	(1.10	)	(14	)%
Per unit of production excluding equity-classified share-based compensation and restructuring expenses ($/BOE)	$	8.33	$	6.91	$	(1.42	)	(21	)%
Per unit of production excluding liability and equity-classified share-based compensation ($/BOE)	$	5.21	$	6.90	$	1.69		24	%

On a unit of production basis, our general and administrative expenses, excluding liability and equity-classified share-based compensation declined during the three months ended March 31, 2014 compared to the 2013 period reflecting the growth in scale of our operations. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the increase in fair value of both the 2013 and 2012 PBRSU grants. The increase in the fair value of the PBRSUs is attributable to our common stock performance relative to a defined peer group. 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, 2014 due primarily to fewer employees receiving grants.

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



	Three Months Ended
	March 31,				Favorable
	2014		2013		(Unfavorable)			% Change
Unproved leasehold amortization	$	3,294	$	5,262	$	1,968		37	%
Geological and geophysical costs	4,500		980		(3,520		)	(359	)%
Other, primarily delay rentals	842		53		(789		)	(1,489	)%
	$	8,636	$	6,295	$	(2,341	)	(37	)%

Unproved leasehold amortization decreased during the three months ended March 31, 2014 due primarily to the classification of our unproved property in the Eagle Ford Shale as a “significant leasehold” effective July 1, 2013. Accordingly, our unproved acreage in this region is no longer subject to systematic amortization. Geological and geophysical costs increased as a result of the acquisition of certain seismic data attributable to our drilling program in South Texas and other regions.



	Three Months Ended
	March 31,						Favorable
	2014			2013			(Unfavorable)			% Change
Interest on borrowings and related fees	$	23,140		$	13,583		$	(9,557	)	(70	)%
Accretion of original issue discount	—			321			321			100	%
Amortization of debt issuance costs	1,012			626			(386		)	(62	)%
Capitalized interest	(1,618		)	(51		)	1,567			3,073	%
	$	22,534		$	14,479		$	(8,055	)	(56	)%
Weighted-average debt outstanding	$	1,276,750		$	619,678
Weighted average interest rate	7.57		%	9.35		%

Interest expense increased during the three months ended March 31, 2014 due primarily to higher overall weighted-average debt outstanding attributable to the issuance of the 8.5% Senior Notes due 2020, or 2020 Senior Notes, in April 2013. The increase in interest expense was partially offset by higher capitalized interest resulting from the significant increase in the value of our proved undeveloped and unproved properties following the EF Acquisition and the absence of accretion of original issue discount attributable to the now retired 10.375% Senior Notes due 2016, or 2016 Senior Notes. The weighted-average interest rate declined during the three months ended March 31, 2014 due primarily to the replacement of the 2016 Senior Notes with the 2020 Senior Notes which carry a lower coupon interest rate.

Our primary sources of liquidity include cash from operating activities, borrowings under our Revolver, proceeds from the sale of non-core assets and, when appropriate, proceeds from capital market transactions including the sale of debt and equity securities. Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among others.

Our business plan contemplates capital expenditures in excess of our projected cash from operating activities for 2014 and 2015. Subject to the variability of commodity prices and production that impact our cash from operating activities, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 2014 capital program with cash from operating activities, borrowings under the Revolver, proceeds from the sales of non-core assets and supplemental issues of debt and equity, if appropriate. We have no debt maturities until September 2017 when the Revolver matures. We believe that our cash from operating activities, borrowing capacity under the Revolver and the projected proceeds from the sales of non-core assets will be sufficient to meet our debt service, preferred stock dividend and working capital requirements as well as our anticipated capital expenditures.

In 2014, we anticipate making capital expenditures, excluding any acquisitions, of up to approximately $653 million. Based on expenditures to date and forecasted activity for the remainder of 2014, we expect to allocate 98% of our capital expenditures to the Eagle Ford Shale. This allocation includes approximately 83 percent for drilling and completions, 13 percent for leasehold acquisition and four percent for pipeline, gathering, seismic, facilities and other projects. The total forecasted activity assumes a drilling program utilizing a minimum of six operated drilling rigs in the Eagle Ford Shale. 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 from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the Cash Flows discussion that follows.

Cash From Operating Activities. Our cash from operating activities is subject to significant volatility due primarily to changes in commodity prices for our products and variations in our production. Accordingly, we actively manage the exposure of our revenues 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, the magnitude of our capital program and our operating strategy. During the three months ended March 31, 2014, our commodity derivatives portfolio resulted in $2.3 million of net cash payments related to higher than anticipated prices received for our crude oil production and $0.8 million of net cash payments attributable to higher than anticipated prices received for our natural gas production.

We have hedged approximately 11,700 barrels of daily crude oil production, or approximately 67 percent of our estimated crude oil production for the remainder of 2014, at a weighted-average floor price of $92.94 per barrel. For 2015, we have hedged approximately 10,000 barrels of daily crude oil production at a weighted-average floor price of $89.41 per barrel. In addition, we have hedged approximately 60 percent of our estimated natural gas production through the third quarter of 2014 at a weighted-average floor price of $4.10 per MMBtu and approximately 20 percent for the 2014 - 2015 winter at a weighted-average floor price of $4.50 per MMBtu.

Revolver Borrowings. The Revolver provides for a $400 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $200 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, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. In May 2014, the borrowing base was increased from $425 million to $475 million, due primarily to our continued development in the Eagle Ford Shale. The next semi-annual redetermination is scheduled for November 2014. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.

For additional information regarding the terms and covenants associated with the Revolver, see the Capitalization discussion that follows. 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, 2014	$	197,922	$	256,000	2.0584	%



	Three Months Ended
	March 31,
	2014			2013			Variance
Cash flows from operating activities
Operating cash flows, net	$	70,590		$	42,006		$	28,584
Working capital changes, net	(323		)	550			(873		)
Commodity derivative settlements received, net:							—
Crude oil	(2,278		)	2,809			(5,087		)
Natural gas	(779		)	748			(1,527		)
Restructuring and exit costs paid	(650		)	(498		)	(152		)
Net cash provided by operating activities	66,560			45,615			20,945
Cash flows from investing activities
Capital expenditures - property and equipment	(159,804		)	(85,973		)	(73,831		)
Proceeds from sales of assets and other, net	95,964			878			95,086
Net cash used in investing activities	(63,840		)	(85,095		)	21,255
Cash flows from financing activities
Proceeds from revolving credit facility borrowings, net	(16,000		)	38,000			(54,000		)
Dividends paid on preferred and common stock	(1,725		)	(1,687		)	(38		)
Other, net	1,085			(61		)	1,146
Net cash provided by (used in) financing activities	(16,640		)	36,252			(52,892		)
Net increase (decrease) in cash and cash equivalents	$	(13,920	)	$	(3,228	)	$	(10,692	)

Cash Flows From Operating Activities. Higher realized cash flows from higher operating profit oil and NGL operations resulted in an increase in our cash flows from operating activities during the three months ended March 31, 2014 compared to the corresponding period in 2013. When comparing the 2014 and 2013 periods, these increases to cash flow were partially offset by the realization of substantially lower net settlements from our commodity derivatives portfolio during the 2013 period due primarily to realized crude oil and natural gas prices exceeding hedged prices and higher restructuring and exit costs payments during the 2014 period due primarily to ongoing contractual payments for firm transportation capacity in the Appalachian region.

Cash Flows From Investing Activities. Capital expenditures were substantially higher during the three months ended March 31, 2014 as compared to the corresponding period during 2013 due primarily to a higher level of drilling activity and lease acquisitions attributable to the Eagle Ford Shale. We operated more drilling rigs and acquired significant acreage in the Eagle Ford Shale during the 2014 period as compared to the 2013 period.

Our capital expenditures during the 2014 period were substantially offset by the receipt in January 2014 of approximately $96 million of net proceeds from sale the of our natural gas gathering assets in South Texas. A portion of those proceeds was used to pay down outstanding borrowings under the Revolver. Net proceeds received during the 2013 period were attributable primarily to the assignment of certain properties in West Virginia associated with our 2012 sale of Appalachian natural gas assets that was not completed until January 2013.



	Three Months Ended
	March 31,
	2014		2013
Oil and gas:
Drilling and completion	$	135,455	$	86,548
Lease acquisitions and other land-related costs¹	36,878		4,997
Geological and geophysical (seismic) costs	4,500		980
Pipeline, gathering facilities and other equipment	5,182		2,958
	182,015		95,483
Other - Corporate	378		116
Total capital program costs	$	182,393	$	95,599

______________________



	Three Months Ended
	March 31,
	2014			2013
Total capital program costs	$	182,393		$	95,599
Increase in accrued capitalized costs	(18,629		)	(7,921		)
Less:
Exploration costs charged to operations:
Geological and geophysical (seismic)	(4,500		)	(980		)
Other, primarily delay rentals	(772		)	(53		)
Transfers from tubular inventory and well materials	(409		)	(736		)
Add:
Tubular inventory and well materials purchased in advance of drilling	103			13
Capitalized interest	1,618			51
Total cash paid for capital expenditures	$	159,804		$	85,973

Cash flows from financing activities for the three months ended March 31, 2014 included net repayments under the Revolver, funded primarily with proceeds from the sale of our natural gas gathering assets in South Texas while the 2013 period includes net borrowings under the Revolver which were used to finance a portion of our capital program. Both periods included dividends paid on our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock. Due primarily to a recent increase in our average stock price, we received proceeds of $1.1 million from the exercise of stock options.

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. As of March 31, 2014, the actual interest rate applicable to the Revolver was 1.9375% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. 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, 2014, commitment fees were being charged at a rate of 0.375%.

2019 Senior Notes. The 7.25% Senior Notes due 2019, or 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 subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. 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 subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

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. During the three months ended March 31, 2014, a total of 19.5 shares, or 1,950 depositary shares, of the 6% Preferred Stock were converted into 32,500 shares of common stock.

Covenant Compliance. The Revolver and the indentures associated with our senior notes require us to maintain certain financial and non-financial covenants. These covenants impose limitations on our ability to pay dividends as well as 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, among

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 Condensed Consolidated Balance Sheets.

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. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2013.

Our interest rate risk is attributable to our borrowings under the Revolver, which is our only long-term debt instrument with variable interest rates. As of March 31, 2014, we had borrowings of $190 million under the Revolver at an interest rate of 1.9375%. Assuming a constant borrowing level of $190 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 $1.9 million on an annual basis.

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, 2014, we reported a commodity derivative asset of $2.0 million. The contracts associated with this position are with five 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, 2014.

During the three months ended March 31, 2014, we reported net commodity derivative losses of $15.7 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.



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2014	Collars	2,500	$	92.00	99.46		$	—	$	740
Third quarter 2014	Collars	2,000	$	90.00	$	94.33	—		827
Fourth quarter 2014	Collars	2,000	$	90.00	$	94.33	—		420
First quarter 2015	Collars	4,000	$	87.50	$	94.66	—		278
Second quarter 2015	Collars	4,000	$	87.50	$	94.66	276		—
Third quarter 2015	Collars	3,000	$	86.67	$	94.73	507		—
Fourth quarter 2015	Collars	3,000	$	86.67	$	94.73	766		—
Second quarter 2014	Swaps	8,500	$	94.00			—		4,984
Third quarter 2014	Swaps	10,000	$	93.21			342		4,410
Fourth quarter 2014	Swaps	10,000	$	93.21			709		2,417
First quarter 2015	Swaps	7,000	$	90.79			—		1,440
Second quarter 2015	Swaps	7,000	$	90.79			—		447
Third quarter 2015	Swaps	6,000	$	90.45			150		—
Fourth quarter 2015	Swaps	6,000	$	90.45			722		—
First quarter 2015	Swaptions	1,000	$	88.00			—		535
Second quarter 2015	Swaptions	1,000	$	88.00			—		534
Third quarter 2015	Swaptions	1,000	$	88.00			—		534
Fourth quarter 2015	Swaptions	1,000	$	88.00			—		534

Natural Gas:		(in MMBtu)	($/MMBtu)
Second quarter 2014	Swaps	15,000	$	4.10			—		474
Third quarter 2014	Swaps	15,000	$	4.10			—		450
Fourth quarter 2014	Swaps	5,000	$	4.50			—		2
First quarter 2015	Swaps	5,000	$	4.50			—		49
Settlements to be paid in subsequent period							—		1,761

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	$	(67.2	)	$	63.1
Effect on the fair value of natural gas derivatives	$	(3.2	)	$	3.2

Effect on the remainder of 2014 operating income, excluding crude oil derivatives	$	41.0		$	(41.0	)
Effect on the remainder of 2014 operating income, excluding natural gas derivatives	$	6.8		$	(6.8	)

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, 2014. 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, 2014, such disclosure controls and procedures were effective.

In February 2014, we completed a project to replace certain of our primary information technology platforms with an integrated ERP system. The platforms replaced included our software for processing accounting, production, lease administration and land transactions. In connection with the implementation of the new ERP system, certain of our business processes and related controls were changed. We believe that we have taken the appropriate steps to monitor the transition to the new ERP system to ensure that there are no adverse impacts to our internal control environment. Apart from the changes attributable to the new ERP system, 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.

Since December 2013, we have been involved in an arbitration with MHR, the seller in our 2013 property acquisition in the Eagle Ford Shale, or EF Acquisition. The arbitration relates to disputes we have with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believe MHR is obligated to transfer to us. MHR has indicated that it owes us approximately $26.5 million; we believe the amount is higher. Both parties submitted rebuttals to initial briefs on March 3, 2014 and submitted additional responses and replies on April 4, 2014. We expect the arbitration to be resolved in the second quarter of 2014.



(10.1)	Penn Virginia Corporation Amended and Restated 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 filed on February 19, 2014).

(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



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



	Three Months
	Ended
	March 31, 2013
Total revenues	$	109,064
Net loss attributable to common shareholders	$	(15,204	)
Loss per share - basic and diluted	$	(0.23	)



	As of
	March 31,			December 31,
	2014			2013
Customers	$	92,612		$	93,288
Joint interest partners	43,860			76,199
Other ¹	31,340			25,538
	167,812			195,025
Less: Allowance for doubtful accounts	(622		)	(622		)
	$	167,190		$	194,403



	As of
	March 31,		December 31,
	2014		2013
Revolving credit facility	$	190,000	$	206,000
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		775,000
	$	1,265,000	$	1,281,000



	As of
	March 31, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	318,000	$	300,000	$	307,500	$	300,000
Senior Notes due 2020	862,188		775,000		837,969		775,000
	$	1,180,188	$	1,075,000	$	1,145,469	$	1,075,000



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



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



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


•	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.


•	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;


•	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 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, 2013.


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



	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	50,220		$	(7,702	)	$	42,518
NGL	(213		)	2,459			2,246
Natural gas	97			6,067			6,164
	$	50,104		$	824		$	50,928


•	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.



	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.50 to 1	3.6 to 1
Current ratio	> 1.00 to 1	1.7 to 1
Interest coverage	> 2.25 to 1	3.5 to 1



	PENN VIRGINIA CORPORATION

	By:	/s/ STEVEN A. HARTMAN
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer

May 12, 2014	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)