10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

________________________________________________________

(Mark One)

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

For the quarterly period ended September 30, 2014 

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 October 24, 2014, 71,558,867 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 September 30, 2014

Table of Contents

Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2014 and 2013	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2014 and 2013	4
	Condensed Consolidated Balance Sheets as of September 30, 2014 and December 31, 2013	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 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	18
	14. Restructuring and Exit Activities	18
	15. Interest Expense	19
	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	24
	Financial Condition	36
	Critical Accounting Estimates	41
3.	Quantitative and Qualitative Disclosures About Market Risk	42
4.	Controls and Procedures	44
Part II - Other Information
1.	Legal Proceedings	45
6.	Exhibits	45
Signatures		46

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Revenues
Crude oil	$	118,716		$	100,564		$	336,382		$	250,489
Natural gas liquids (NGLs)	9,790			8,212			27,200			22,652
Natural gas	13,354			12,872			47,859			40,465
Gain (loss) on sales of property and equipment, net	63,520			(186		)	120,295			(479		)
Other, net	16			151			2,886			1,339
Total revenues	205,396			121,613			534,622			314,466
Operating expenses
Lease operating	15,296			8,457			38,103			24,891
Gathering, processing and transportation	4,893			3,039			11,380			9,598
Production and ad valorem taxes	7,690			6,597			22,505			19,532
General and administrative	11,527			12,677			43,055			39,276
Exploration	1,986			3,957			13,995			18,097
Depreciation, depletion and amortization	71,999			62,450			215,623			178,355
Impairments	6,084			132,224			123,992			132,224
Total operating expenses	119,475			229,401			468,653			421,973
Operating income (loss)	85,921			(107,788		)	65,969			(107,507		)
Other income (expense)
Interest expense	(21,953		)	(20,218		)	(67,716		)	(56,505		)
Loss on extinguishment of debt	—			—			—			(29,157		)
Derivatives	66,457			(24,035		)	8,130			(23,208		)
Other	1,349			35			1,380			79
Income (loss) before income taxes	131,774			(152,006		)	7,763			(216,298		)
Income tax (expense) benefit	(42,113		)	53,106			339			75,577
Net income (loss)	89,661			(98,900		)	8,102			(140,721		)
Preferred stock dividends	(7,641		)	(1,725		)	(11,081		)	(5,175		)
Induced conversion of preferred stock	(888		)	—			(4,256		)	—
Net income (loss) attributable to common shareholders	$	81,132		$	(100,625	)	$	(7,235	)	$	(145,896	)
Net income (loss) per share:
Basic	$	1.13		$	(1.54	)	$	(0.11	)	$	(2.38	)
Diluted	$	0.87		$	(1.54	)	$	(0.11	)	$	(2.38	)
Weighted average shares outstanding – basic	71,536			65,465			67,909			61,272
Weighted average shares outstanding – diluted	103,606			65,465			67,909			61,272

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					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Net income (loss)	$	89,661	$	(98,900	)	$	8,102	$	(140,721	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $14 and $40 in 2014 and $10 and $30 in 2013	25		18			74		56
	25		18			74		56
Comprehensive income (loss)	$	89,686	$	(98,882	)	$	8,176	$	(140,665	)

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
	September 30,			December 31,
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	123,690		$	23,474
Accounts receivable, net of allowance for doubtful accounts	188,683			194,403
Derivative assets	13,680			3,830
Deferred income taxes	6,040			6,065
Other current assets	6,951			5,924
Total current assets	339,044			233,696
Property and equipment, net (successful efforts method)	2,342,903			2,237,304
Derivative assets	8,572			1,552
Other assets	31,860			34,535
Total assets	$	2,722,379		$	2,507,087
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	276,593		$	248,004
Derivative liabilities	1,045			10,141
Total current liabilities	277,638			258,145
Other liabilities	125,646			33,386
Deferred income taxes	145,428			145,752
Long-term debt	1,075,000			1,281,000
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,945 and 11,500 shares issued as of September 30, 2014 and December 31, 2013 and Series B – 32,500 shares issued as of September 30, 2014, each with a redemption value of $10,000 per share	4,044			1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 71,557,951 and 65,306,748 shares issued as of September 30, 2014 and December 31, 2013, respectively	528			466
Paid-in capital	1,205,302			891,351
Accumulated deficit	(111,415		)	(104,180		)
Deferred compensation obligation	3,106			2,792
Accumulated other comprehensive income	341			267
Treasury stock – 246,352 and 233,063 shares of common stock, at cost, as of September 30, 2014 and December 31, 2013, respectively	(3,239		)	(3,042		)
Total shareholders’ equity	1,098,667			788,804
Total liabilities and shareholders’ equity	$	2,722,379		$	2,507,087

See accompanying notes to condensed consolidated financial statements.

5

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Nine Months Ended
	September 30,
	2014			2013
Cash flows from operating activities
Net income (loss)	$	8,102		$	(140,721	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss on extinguishment of debt	—			29,157
Depreciation, depletion and amortization	215,623			178,355
Impairments	123,992			132,224
Accretion of firm transportation obligation	991			1,263
Derivative contracts:
Net losses (gains)	(8,130		)	23,208
Cash settlements, net	(17,836		)	1,625
Deferred income tax benefit	(339		)	(75,577		)
(Gain) loss on sales of assets, net	(120,295		)	479
Non-cash exploration expense	8,387			14,167
Non-cash interest expense	3,114			2,846
Share-based compensation (equity-classified)	2,638			4,781
Other, net	325			198
Changes in operating assets and liabilities, net	(16,122		)	52,829
Net cash provided by operating activities	200,450			224,834
Cash flows from investing activities
Acquisition, net	—			(358,239		)
Receipts (payments) to settle working capital adjustments assumed in acquisition, net	33,712			(43,023		)
Capital expenditures – property and equipment	(545,031		)	(356,964		)
Proceeds from sales of assets, net	311,913			653
Net cash used in investing activities	(199,406		)	(757,573		)
Cash flows from financing activities
Proceeds from the issuance of preferred stock, net	313,330			—
Payments made to induce conversion of preferred stock	(4,256		)	—
Proceeds from the issuance of senior notes	—			775,000
Retirement of senior notes	—			(319,090		)
Proceeds from revolving credit facility borrowings	377,000			219,000
Repayment of revolving credit facility borrowings	(583,000		)	(91,000		)
Debt issuance costs paid	(151		)	(25,199		)
Dividends paid on preferred stock	(5,165		)	(5,137		)
Other, net	1,414			(164		)
Net cash provided by financing activities	99,172			553,410
Net increase in cash and cash equivalents	100,216			20,671
Cash and cash equivalents – beginning of period	23,474			17,650
Cash and cash equivalents – end of period	$	123,690		$	38,321
Supplemental disclosures:
Cash paid for:
Interest	$	47,778		$	24,251
Income taxes	$	100		$	—

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 September 30, 2014

(in thousands, except per share amounts)

1.  Organization

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 drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma and the Haynesville Shale and Cotton Valley in East Texas.

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, 2013. Operating results for the nine months ended September 30, 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.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014-09 on our ongoing financial reporting.

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 an increase in the borrowing base under our revolving credit facility (the “Revolver”) as discussed in Note 7, 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.

3. Acquisitions and Divestitures

Acquisitions

Undeveloped Eagle Ford Acreage

In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) acres in the Eagle Ford in Lavaca County, Texas. The transaction closed in August 2014 for a purchase price of $45.6 million, of which $34.9 million was paid at closing and the balance of $10.7 million will be paid over the next three years as a drilling carry.

EF Acquisition

On April 24, 2013 (the “Acquisition Date”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford (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 Magnum Hunter Resources Corporation (“MHR”), the seller in the EF Acquisition, 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. Subsequent to the Acquisition Date and through December 31, 2013, we paid a total of $22.5 million, net to settle working capital adjustments assumed in the EF Acquisition.

Commencing December 2013, we were involved in arbitration with MHR. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. In July 2014, we received the arbitrator’s determination, which required MHR to pay us a total of $35.1 million, including purchase price adjustments, revenue suspense funds due to partners and royalty owners and

7

interest ($1.3 million) on the funds since the Acquisition Date. Payment of the arbitration settlement was made by MHR in August 2014.

We accounted for the EF Acquisition by applying the acquisition method of accounting as of the Acquisition Date. The following table represents the fair values assigned to the net assets acquired and the consideration paid:

Assets
Oil and gas properties – proved	$	267,688
Oil and gas properties – unproved	119,709
Accounts receivable, net	107,345
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 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 periods 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.

	Nine Months Ended
	September 30, 2013
Total revenues	$	344,412
Net loss attributable to common shareholders	$	(124,172	)
Loss per share – basic and diluted	$	(1.84	)

Divestitures

In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC (“Republic”) for proceeds of $147.1 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate pipeline transportation services for a substantial portion of our current and future South Texas crude oil and condensate production. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred and will be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be 2015. The deferred gain is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

In July 2014, we sold our Selma Chalk assets in Mississippi for proceeds of $67.9 million, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 with respect to these assets.

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP (“AMID”) for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of

8

our current and future South Texas natural gas production. 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 and $0.3 million of the deferred gain during the three and nine months ended September 30, 2014, respectively. As of September 30, 2014, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $9.9 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

4.       Accounts Receivable and Major Customers

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

	As of
	September 30,			December 31,
	2014			2013
Customers	$	97,139		$	93,288
Joint interest partners	84,112			76,199
Other 1	7,608			25,538
	188,859			195,025
Less: Allowance for doubtful accounts	(176		)	(622		)
	$	188,683		$	194,403

______________________

¹ The balance as of December 31, 2013 was comprised substantially of amounts due from MHR and other parties for purchase price adjustments attributable to the EF Acquisition, which were received in August 2014.

For the nine months ended September 30, 2014, four customers accounted for $267.0 million, or approximately 65%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2014 were $86.2 million, $72.5 million, $55.8 million and $52.6 million or 21%, 18%, 13% and 13% of the consolidated total, respectively. As of September 30, 2014, $65.2 million, or approximately 67% of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2013, three customers accounted for $124.1 million, or approximately 40% of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2013 were $51.9 million, $37.7 million and $34.5 million or approximately 17%, 12% and 11% of the consolidated total, respectively. As of December 31, 2013, $34.8 million, or approximately 37% 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.

5. Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility and, from time to time, the volatility in interest rates attributable to our debt instruments. Our derivative instruments are not formally designated as hedges.

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.

9

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.

The following table sets forth our commodity derivative positions as of September 30, 2014:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2014	Collars	2,000	$	90.00	94.33	$	264	$	—
First quarter 2015	Collars	4,000	$	87.50	94.66	649		—
Second quarter 2015	Collars	4,000	$	87.50	94.66	947		—
Third quarter 2015	Collars	3,000	$	86.67	94.73	770		—
Fourth quarter 2015	Collars	3,000	$	86.67	94.73	838		—
Fourth quarter 2014	Swaps	11,000	$	93.45		3,301		40
First quarter 2015	Swaps	9,000	$	91.81		2,197		—
Second quarter 2015	Swaps	9,000	$	91.81		2,835		—
Third quarter 2015	Swaps	8,000	$	91.06		2,352		—
Fourth quarter 2015	Swaps	8,000	$	91.06		2,432		—
First quarter 2016	Swaps	3,000	$	90.84		1,176		—
Second quarter 2016	Swaps	3,000	$	90.84		1,284		—
Third quarter 2016	Swaps	3,000	$	90.84		1,395		—
Fourth quarter 2016	Swaps	3,000	$	90.84		1,447		—
First quarter 2015	Swaptions	1,000	$	88.00		—		252
Second quarter 2015	Swaptions	1,000	$	88.00		—		251
Third quarter 2015	Swaptions	1,000	$	88.00		—		251
Fourth quarter 2015	Swaptions	1,000	$	88.00		—		251
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2014	Swaps	5,000	$	4.50		185		—
First quarter 2015	Swaps	5,000	$	4.50		129		—
Settlements to be received in subsequent period						52		—

Interest Rate Swaps

During the nine months ended September 30, 2014 and 2013, we had no interest rate derivative instruments in place.

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Impact by contract type:
Commodity contracts	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Interest rate contracts	—			—			—			—
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	(7,557	)	$	(4,165	)	$	(17,836	)	$	1,625
Interest rate contract settlements	—			—			—			—
	(7,557		)	(4,165		)	(17,836		)	1,625
Gains (losses) attributable to:
Commodity contracts	74,014			(19,870		)	25,966			(24,833		)
Interest rate contracts	—			—			—			—
	74,014			(19,870		)	25,966			(24,833		)
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)

The effects of derivative gains and (losses) and cash settlements of our commodity 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 (gains) and Cash settlements, net captions.

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
		September 30, 2014				December 31, 2013
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	13,680	$	1,045	$	3,830	$	10,141
Interest rate contracts	Derivative assets/liabilities – current	—		—		—		—
		13,680		1,045		3,830		10,141
Commodity contracts	Derivative assets/liabilities – noncurrent	8,572		—		1,552		—
Interest rate contracts	Derivative assets/liabilities – noncurrent	—		—		—		—
		8,572		—		1,552		—
		$	22,252	$	1,045	$	5,382	$	10,141

As of September 30, 2014, we reported a commodity derivative asset of $22.3 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with two 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.

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6. Property and Equipment

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

	As of
	September 30,			December 31,
	2014			2013
Oil and gas properties:
Proved	$	450,601		$	460,255
Unproved	137,464			101,520
Total oil and gas properties	588,065			561,775
Other property and equipment:
Wells, equipment and facilities	2,743,466			2,593,700
Support equipment	23,153			21,513
Total other property and equipment	2,766,619			2,615,213
	3,354,684			3,176,988
Accumulated depreciation, depletion and amortization	(1,011,781		)	(939,684		)
	$	2,342,903		$	2,237,304

In the three months ended September 30, 2014, we recognized an oil and gas asset impairment of $6.1 million in connection with an exploration prospect drilled in the Mid-Continent region. In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets in Mississippi. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 to write these assets down to fair value. The sale was completed in July 2014.

7. Long-Term Debt

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

	As of
	September 30,		December 31,
	2014		2013
Revolving credit facility	$	—	$	206,000
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		775,000
	$	1,075,000	$	1,281,000

Revolving Credit Facility

The Revolver provides for a $450 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $150 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. Upon the closing of the sale of our Selma Chalk assets in the third quarter of 2014, the borrowing base was reduced from $475 million to $437.5 million. In October 2014, the borrowing base was increased to $500 million in connection with the regular semi-annual redetermination. The next semi-annual redetermination is scheduled for May 2015. In addition, the Revolver was amended to clarify the requirements with respect to pro forma treatment of material acquisitions and dispositions for purposes of the leverage ratio covenant under the Revolver. 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 September 30, 2014. As of September 30, 2014, our available borrowing capacity under the Revolver was $435.8 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%, plus, in each case, 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 September 30, 2014, the actual interest rate on the outstanding borrowings under the Revolver was 1.6875% which is derived

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from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.50%. 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 September 30, 2014, commitment fees were being charged at a rate of 0.375%.

The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries (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 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 leverage ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.25 to 1.0 through December 31, 2014 and then 4.0 to 1.0 through maturity.

2019 Senior Notes

Our 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 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

Our 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 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 2019 Senior Notes and 2020 Senior Notes 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 to obtain funds from the Guarantor Subsidiaries through dividends, advances or loans.

8. Income Taxes

We recognized an income tax benefit for the nine months ended September 30, 2014 at an effective rate of 4.4%. The annual effective tax rate applied to the nine months ended September 30, 2014 includes federal taxes at the statutory rate of 35%; however, the federal effect is almost entirely offset by state income tax effects, which include a deferred tax benefit associated with an expected decrease in the effective state income tax rate in future periods. The benefit is due primarily to a shift in the source of our expected future state taxable income as a result of the recent sale of all of our properties in Mississippi. Our effective tax rate also 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 asset.

Due to the losses incurred during the three and nine months endedSeptember 30, 2013, we recognized income tax benefits at an effective 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.

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9. Additional Balance Sheet Detail

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

	As of
	September 30,		December 31,
	2014		2013
Other current assets:
Tubular inventory and well materials	$	3,946	$	2,271
Prepaid expenses	2,905		3,653
Other	100		—
	$	6,951	$	5,924
Other assets:
Debt issuance costs	$	27,277	$	30,239
Assets of supplemental employee retirement plan (“SERP”)	4,021		3,734
Other	562		562
	$	31,860	$	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	$	105,888	$	120,278
Drilling and other lease operating costs	56,585		51,529
Royalties	46,672		39,929
Compensation – related	10,947		8,584
Interest	37,417		15,718
Preferred stock dividends	7,638		1,725
Other	11,446		10,241
	$	276,593	$	248,004
Other liabilities:
Deferred gains on sale of assets	$	90,675	$	—
Firm transportation obligation	12,352		13,245
Asset retirement obligations (“AROs”)	5,808		6,437
Defined benefit pension obligations	1,461		1,579
Postretirement health care benefit obligations	1,154		1,023
Deferred compensation – SERP obligations and other	4,130		3,883
Other	10,066		7,219
	$	125,646	$	33,386

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10. 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 September 30, 2014, 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
	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	300,750	$	300,000	$	307,500	$	300,000
Senior Notes due 2020	821,500		775,000		837,969		775,000
	$	1,122,250	$	1,075,000	$	1,145,469	$	1,075,000

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 September 30, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets – current	$	13,680		$	—		$	13,680		$	—
Commodity derivative assets – noncurrent	8,572			—			8,572			—
Assets of SERP	4,021			4,021			—			—
Liabilities:
Commodity derivative liabilities – current	(1,045		)	—			(1,045		)	—
Commodity derivative liabilities – noncurrent	—			—			—			—
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—			—

	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 nine months ended September 30, 2014 and 2013.

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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: 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 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.

11. 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 remaining terms of up to 11 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 scheduled terms. The amount of penalty is based on the number of days remaining in the contractual term. As of September 30, 2014, the penalty amount would have been $24.4 million had we terminated our agreements on that date.

Other Commitments

We have 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.

We have a long-term agreement that provides natural gas gathering, compression and gas lift services for a substantial portion of our natural gas 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 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.

As discussed in Note 3, we entered into long-term agreements that provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our obligations under the agreements are expected to begin in 2015 when construction of the gathering, transportation and delivery point facilities is completed. The agreements require us to commit certain minimum volumes of crude oil production for the first ten years of the agreements’ terms, which will result in minimum fee requirements of $13.7 million on an annual basis.

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 September 30, 2014. As of September 30, 2014, we also have AROs of approximately $5.8 million attributable to the plugging of abandoned wells.

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12. Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for the nine months ended September 30, 2014 and 2013:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2013			Net Income			Offering		Declared 1			Changes 2			2014
Preferred stock 3	$	1,150		$	—		$	3,250	$	—		$	(356	)	$	4,044
Common stock 3	466			—			—		—			62			528
Paid-in capital 3	891,351			—			310,080		—			3,871			1,205,302
Accumulated deficit 3	(104,180		)	8,102			—		(11,081		)	(4,256		)	(111,415		)
Deferred compensation obligation	2,792			—			—		—			314			3,106
Accumulated other comprehensive income 4	267			—			—		—			74			341
Treasury stock	(3,042		)	—			—		—			(197		)	(3,239		)
	$	788,804		$	8,102		$	313,330	$	(11,081	)	$	(488	)	$	1,098,667
	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2012			Net Loss			Offering		Declared 1			Changes 2			2013
Preferred stock	$	1,150		$	—		$	—	$	—		$	—		$	1,150
Common stock 5	364			—			—		—			101			465
Paid-in capital 5	849,046			—			—		—			46,404			895,450
Retained earnings	45,790			(140,721		)	—		(5,175		)	—			(100,106		)
Deferred compensation obligation	3,111			—			—		—			(384		)	2,727
Accumulated other comprehensive loss 4	(982		)	—			—		—			56			(926		)
Treasury stock	(3,363		)	—			—		—			386			(2,977		)
	$	895,116		$	(140,721	)	$	—	$	(5,175	)	$	46,563		$	795,783

______________________

¹ Includes dividends of $450.00 per share on our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) and $198.33 per share on our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”).

² Includes equity-classified share-based compensation of $2,638 and $4,781 for the nine months ended September 30, 2014 and 2013.

³ A total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5,924,706 shares of our common stock during the nine months ended September 30, 2014. We made payments of $4.3 million to induce the conversion of 3,527 of these shares.

⁴ The Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the nine months ended September 30, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $114 and $86 and are presented above net of taxes of $40 and $30.

⁵ Includes the Shares, with a fair value of $4.23 per share, that were issued to MHR in connection with the EF Acquisition.

In June 2014, we completed a private offering of 3,250,000 depositary shares each representing a 1/100^th interest in a share, or 32,500 shares, of our Series B Preferred Stock, which provided approximately $313 million of proceeds, net of underwriting fees and issuance costs.

The annual dividend on each share of the Series B 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 Series B 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 $18.34 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 545.17 shares of our common stock for each share of the Series B Preferred Stock. The initial conversion price represents a premium of 30 percent relative to the last reported sales price of $14.11 per common share prior to the offering of the Series B Preferred Stock. The Series B Preferred Stock is not redeemable by us or the holders at any time. At any time on or after July 15, 2019, we may, at our option, cause all outstanding shares of the Series B 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 Series B 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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13. Share-Based Compensation

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.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014			2013		2014		2013
Equity-classified awards:
Stock option awards	$	403		$	612	$	1,193	$	2,518
Common, deferred and restricted stock and stock unit awards	584			398		1,445		2,263
	987			1,010		2,638		4,781
Liability-classified awards	(360		)	1,095		6,632		1,544
	$	627		$	2,105	$	9,270	$	6,325

14. Restructuring and Exit Activities

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Balance at beginning of period	$	15,559		$	16,677		$	16,090		$	17,263
Employee, office and other costs accrued, net	18			2			27			5
Accretion of firm transportation obligation	407			410			991			1,263
Cash payments, net	(857		)	(705		)	(1,981		)	(2,147		)
Balance at end of period	$	15,127		$	16,384		$	15,127		$	16,384

Restructuring charges are included in the General and administrative caption on our Condensed Consolidated Statements of Operations. The accretion of the firm transportation 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 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 September 30, 2014, $2.7 million of the total obligations are classified as current while the remaining $12.4 million are classified as noncurrent.

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15. Interest Expense

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Interest on borrowings and related fees	$	22,559		$	22,754		$	69,477		$	57,239
Accretion of original issue discount 1	—			—			—			431
Amortization of debt issuance costs	1,063			961			3,114			2,415
Capitalized interest	(1,669		)	(3,497		)	(4,875		)	(3,580		)
	$	21,953		$	20,218		$	67,716		$	56,505

_____________________

¹ Represents accretion of original issue discount attributable to our 10.375% Senior Notes due 2016 that were retired in 2013.

16. 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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income (loss)	$	89,661		$	(98,900	)	$	8,102		$	(140,721	)
Less: Preferred stock dividends	(7,641		)	(1,725		)	(11,081		)	(5,175		)
Less: Induced conversion of preferred stock	(888		)	—			(4,256		)	—
Net income (loss) attributable to common shareholders – basic	$	81,132		$	(100,625	)	$	(7,235	)	$	(145,896	)
Add: Preferred stock dividends 1	7,641			—			—			—
Add: Induced conversion of preferred stock 1	888			—			—			—
Net income (loss) attributable to common shareholders – diluted	$	89,661		$	(100,625	)	$	(7,235	)	$	(145,896	)
Weighted-average shares – basic	71,536			65,465			67,909			61,272
Effect of dilutive securities 2	32,070			—			—			—
Weighted-average shares – diluted	103,606			65,465			67,909			61,272

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2014, approximately 24.9 million potentially dilutive securities, including the Series A Preferred Stock and Series B 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. For the three and nine months ended September 30, 2013, approximately 19.2 million and less than 0.1 million, respectively, potentially dilutive securities, including the Series A 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, or Revolver;

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

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

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

• drilling and operating risks;

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

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

• leasehold terms expiring before production can be established;

• environmental obligations, costs and 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;

• compliance with and 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 factors set forth in our periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.

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. All subsequent written and oral forward-looking statements attributable to the Company or persons acting on its behalf are expressly qualified in their entirety by these cautionary statements. 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 except as may be required by applicable law.

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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,” 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, and certain amounts for the 2013 periods have been reclassified to conform to the current year presentation. 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.

Overview of Business

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 drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma and the Haynesville Shale and Cotton Valley in East Texas. As of December 31, 2013, we had proved oil and gas reserves of approximately 122 million barrels of oil equivalent, or MMBOE, excluding our recently divested Selma Chalk assets in Mississippi.

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Total production (MBOE)	2,089			1,807			5,973			4,982
Daily production (BOEPD)	22,706			19,638			21,881			18,249
Crude oil and NGL production (MBbl)	1,556			1,208			4,238			3,160
Crude oil and NGL production as a percent of total	74		%	67		%	71		%	63		%
Product revenues, as reported	$	141,860		$	121,648		$	411,441		$	313,606
Product revenues, as adjusted for derivatives	$	134,303		$	117,483		$	393,605		$	315,231
Crude oil and NGL revenues as a percent of total, as reported	91		%	89		%	88		%	87		%
Realized prices:
Crude oil ($/Bbl)	$	95.19		$	105.37		$	97.72		$	103.87
NGL ($/Bbl)	$	31.75		$	32.34		$	34.18		$	30.27
Natural gas ($/Mcf)	$	4.17		$	3.58		$	4.60		$	3.70
Aggregate ($/BOE)	$	67.91		$	67.33		$	68.88		$	62.95
Production and lifting costs ($/BOE):
Lease operating	$	7.32		$	4.68		$	6.38		$	5.00
Gathering, processing and transportation	2.34			1.68			1.91			1.93
Production and ad valorem taxes ($/BOE)	3.68			3.65			3.77			3.92
General and administrative ($/BOE) 1	5.22			5.85			5.66			6.64
Total operating costs ($/BOE)	$	18.56		$	15.86		$	17.72		$	17.49
Depreciation, depletion and amortization ($/BOE)	$	34.47		$	34.57		$	36.10		$	35.80
Cash provided by operating activities	$	101,257		$	95,083		$	200,450		$	224,834
Cash paid for capital expenditures	$	194,451		$	127,645		$	545,031		$	356,964
Cash and cash equivalents at end of period							$	123,690		$	38,321
Debt outstanding at end of period							$	1,075,000		$	1,203,000
Credit available under revolving credit facility at end of period 2							$	435,846		$	218,968
Net development wells drilled	15.4			8.9			44.2			28.2

_______________________

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.47 and $0.44 for the three and nine months ended September 30, 2014 and $0.56 and $0.96 for the three and nine months ended September 30, 2013 and liability-classified share-based compensation of ($0.17) and $1.11 for the three and nine months ended September 30, 2014 and $0.61 and $0.31 for the three and nine months ended September 30, 2013.

² As reduced by outstanding borrowings and letters of credit.

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In the three months ended September 30, 2014, our crude oil and NGL production increased to 74 percent from 70 percent of our total production compared to the three month period ended June 30, 2014, continuing a trend consistent with our liquids-focused strategy. Our cash margin, or aggregate realized prices less total operating costs excluding equity-classified and liability-classified share-based compensation, increased $5.70 per barrel of oil equivalent, or BOE, or 13 percent, to $51.16 per BOE for the nine months ended September 30, 2014 from $45.46 per BOE for the corresponding period in 2013. The higher cash margins are attributable primarily to higher liquids production and higher NGL and natural gas prices compared to the corresponding periods of the prior year. Consistent with our growth in cash margins, our cash from operating activities, excluding working capital changes, increased approximately $45 million, or 26 percent, for the nine months ended September 30, 2014 compared to the corresponding period of the prior year, despite declining crude oil prices.

Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. Since our initial acquisition in this region in 2010, we have a total of 245 gross wells, including 213 gross wells that are operated by us and 32 gross wells that are operated by our partners, through October 24, 2014. We are currently operating a total of eight drilling rigs in the Eagle Ford. Our capital program, which is substantially dedicated to this play, is being financed with a combination of cash from operating activities, proceeds from the sale of assets, borrowings under our revolving credit facility, or the Revolver, and our recent preferred equity offering.

To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The Financial Condition discussion that follows and Note 5 to the Condensed Consolidated Financial Statements provides a detailed summary of our open commodity derivative positions as well as the historical results of our hedging program for the three and nine months ended September 30, 2014 and 2013. With respect to crude oil prices, we have hedged approximately 13,000, 12,000 and 3,000 barrels of daily crude oil production for weighted-average floor/swap prices of $92.92, $90.20 and $90.84 per barrel for the remainder of 2014, calendar 2015 and calendar 2016, respectively.

Key Developments

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, (ii) increasing our borrowing base and amendments to the Revolver, (iii) the acquisition of additional Eagle Ford acreage, (iv) the sale of Mississippi assets, South Texas oil gathering rights and natural gas gathering and gas lift assets and (v) the resolution of arbitration related to our 2013 Eagle Ford acquisition and (vi) recent preferred stock transactions.

Drilling Results and Future Development Plans for the Eagle Ford

During the three months ended September 30, 2014, we completed and turned in line 17 gross (8.3 net) operated wells (excluding four shallow wells and one non-operated well) in the Eagle Ford. By the end of September 2014, we increased our operated drilling rigs in the Eagle Ford from six to eight. Our Eagle Ford production was 16,929 net barrels of oil equivalent per day, or BOEPD, during the three months ended September 30, 2014 with oil comprising 12,909 BOPD, or 76 percent, and NGLs and natural gas comprising approximately 13 percent and 11 percent, respectively. Our third quarter Eagle Ford oil production was 10 percent higher than our second quarter production of 11,744 BOPD. In the month of September 2014, our average Eagle Ford production was 17,936 BOEPD, 75 percent of which was crude oil, 13 percent was NGLs and 12 percent was natural gas.

In the Eagle Ford, we have 12 gross (8.5 net) wells completing or flowing back (including six gross (5.7 net) Upper Eagle Ford, or Marl, wells), 14 gross (8.5 net) wells waiting on completion (including six gross (5.2 net) Upper Eagle Ford wells) and eight gross (6.3 net) wells being drilled (including three (2.9 net) Upper Eagle Ford wells) as of October 24, 2014.

Thus far in the second half of 2014, we have completed six Upper Eagle Ford wells, all of which are flowing back and being tested. Through October 24, 2014, we have completed eight Upper Eagle Ford wells and for the remainder of 2014 we expect ten additional Upper Eagle Ford wells to be drilled, completed and turned in line.

We expect to turn in line 33 gross (23.0 net) wells, excluding three non-operated wells, during the fourth quarter of 2014, for an estimated total of 88 gross (55.9 net) operated wells, excluding six shallow and eight non-operated wells, being turned in line during 2014. For 2014, we expect to turn in line 18 gross (16.4 net) Upper Eagle Ford wells.

Borrowing Base Increase and Amendments to the Revolver

In October 2014, the borrowing base under the Revolver was increased to $500 million from $437.5 million in connection with our regular semi-annual redetermination. In addition, the Revolver was amended to clarify the requirements with respect to pro forma treatment of material acquisitions and dispositions for purposes of the leverage ratio covenant.

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Acquisition of Additional Eagle Ford Acreage

In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) acres in Lavaca County, Texas, the vast majority of which are in the “volatile oil window” of the Eagle Ford. The transaction closed in August 2014 for $45.6 million, of which $34.9 million was paid at closing and the balance of $10.6 million will be paid over the next three years as a drilling carry. We anticipate commencing drilling activities on this acreage in 2015. The transaction, combined with recent leasing, brings our total Eagle Ford acreage position to approximately 145,500 gross (104,300 net) acres. The acquired acreage, most of which we expect will be prospective in the Upper Eagle Ford, is adjacent to our Shiner area.

Sale of Mississippi Assets

In July 2014, we sold our Selma Chalk assets in Mississippi for proceeds of $67.9 million, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 to write down these assets to their estimated fair value.

Sale of Rights to Construct an Oil Gathering System in South Texas

In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC, or Republic, for proceeds of $147.1 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate pipeline transportation services for a substantial portion of our current and future South Texas crude oil and condensate production. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred and will be recognized over a twenty-five year period after the system has been constructed and is operational, currently expected to be 2015.

Sale of South Texas Natural Gas Gathering and Gas Lift Assets

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP, or AMID, for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of our current and future South Texas natural gas production. 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.

Settlement of Arbitration

Commencing December 2013, we were involved in arbitration with Magnum Hunter Resources Corporation, or MHR, the seller in our 2013 Eagle Ford property acquisition, or the EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. In July 2014, we received the arbitrator’s determination, which required MHR to pay us a total of $35.1 million, including purchase price adjustments, revenue suspense funds due to partners and royalty owners and interest ($1.3 million) on the funds since the date of acquisition. Payment of the arbitration settlement was made by MHR in August 2014.

Preferred Stock Offering and Induced Conversion of Outstanding Preferred Stock

In June 2014, we completed a private offering of 3,250,000 depositary shares each representing 1/100th interest in a share of our 6% Series B Convertible Perpetual Preferred Stock, or the Series B Preferred Stock, that provided approximately $313 million of proceeds, net of underwriting fees and issuance costs. Concurrent with the Series B Preferred Stock offering and subsequently in July 2014, we paid a total of $4.3 million to induce the conversion of 3,527 shares, or 352,732 depositary shares, of our 6% Series A Convertible Perpetual Preferred Stock, or the Series A Preferred Stock. A total of 5.9 million shares of our common stock were issued in connection with the induced conversion of the Series A Preferred Stock.

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Results of Operations

Three Months Ended September 30, 2014 Compared to the Three Months Ended September 30, 2013

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				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	1,187.7	897.9	289.8		12,909.3	9,759.4	3,149.9		32	%
East Texas	13.7	15.5	(1.8	)	148.7	168.1	(19.4	)	(12	)%
Mid-Continent	44.6	37.8	6.8		484.9	410.8	74.1		18	%
Mississippi	1.3	3.2	(2.0	)	13.6	35.1	(21.5	)	(61	)%
Appalachia	—	—	—		—	—	—		—	%
	1,247.2	954.4	292.8		13,556.5	10,373.4	3,183.1		31	%

NGLs	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	202.2	142.1	60.2		2,198.1	1,544.0	654.1		42	%
East Texas	34.3	42.5	(8.3	)	372.7	462.3	(89.7	)	(19	)%
Mid-Continent	71.7	69.3	2.4		779.8	753.3	26.5		4	%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	—	—		—	—	—		—	%
	308.3	253.9	54.4		3,350.6	2,759.7	590.9		21	%

Natural gas	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	1,005	693	312		10.9	7.5	3.4		45	%
East Texas	958	1,129	(171	)	10.4	12.3	(1.9	)	(15	)%
Mid-Continent	848	674	174		9.2	7.3	1.9		26	%
Mississippi	353	1,057	(705	)	3.8	11.5	(7.7	)	(67	)%
Appalachia	37	37	(1	)	0.4	0.4	—		(2	)%
	3,201	3,591	(390	)	34.8	39.0	(4.2	)	(11	)%

Combined total	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	1,557	1,155	402		16,928.9	12,558.9	4,370.0		35	%
East Texas	208	246	(39	)	2,256.9	2,676.0	(419.2	)	(16	)%
Mid-Continent	258	219	38		2,801.7	2,385.5	416.2		17	%
Mississippi	60	179	(119	)	652.4	1,950.5	(1,298.1	)	(67	)%
Appalachia	6	6	—		66.2	67.5	(1.3	)	(2	)%
	2,089	1,807	282		22,706.0	19,638.5	3,067.6		16	%

Total production increased during the three months ended September 30, 2014 compared to the corresponding period of 2013 due primarily to the continued expansion of our Eagle Ford development program in South Texas. The increase was partially offset by natural production declines in our East Texas region as well as the sale of our Mississippi Selma Chalk assets in July 2014. Approximately 74 percent of total production during the three months ended September 30, 2014 was attributable to oil and NGLs, which represents an increase of approximately 29 percent over the prior year period. During the three months

24

ended September 30, 2014, our Eagle Ford production represented approximately 75 percent of our total production compared to approximately 64 percent from this play during the corresponding period of 2013.

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							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	113,454	$	94,794	$	18,660		$	95.53	$	105.58	$	(10.05	)
East Texas	1,303		1,629		(326		)	95.26		105.32		(10.07		)
Mid-Continent	3,837		3,789		48			86.01		100.24		(14.24		)
Mississippi	122		352		(230		)	97.52		109.05		(11.52		)
Appalachia	—		—		—			—		—		—
	$	118,716	$	100,564	$	18,152		$	95.19	$	105.37	$	(10.18	)

NGLs	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	5,079	$	3,919	$	1,160		$	25.12	$	27.59	$	(2.47	)
East Texas	1,496		1,858		(362		)	43.64		43.68		(0.05		)
Mid-Continent	3,215		2,435		780			44.81		35.14		9.68
Mississippi	—		—		—			—		—		—
Appalachia	—		—		—			—		—		—
	$	9,790	$	8,212	$	1,578		$	31.75	$	32.34	$	(0.59	)

Natural gas	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	4,143	$	2,560	$	1,583		$	4.12	$	3.69	$	0.43
East Texas	3,839		4,001		(162		)	4.01		3.54		0.46
Mid-Continent	3,775		2,367		1,408			4.45		3.51		0.94
Mississippi	1,513		3,824		(2,311		)	4.29		3.62		0.67
Appalachia	84		120		(36		)	2.30		3.22		NM
	$	13,354	$	12,872	$	482		$	4.17	$	3.58	$	0.59

Combined total	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per BOE)
Texas
South Texas	$	122,676	$	101,273	$	21,403		$	78.77	$	87.65	$	(8.88	)
East Texas	6,638		7,488		(850		)	31.97		30.41		1.56
Mid-Continent	10,827		8,591		2,236			42.01		39.15		2.86
Mississippi	1,635		4,176		(2,541		)	27.24		23.27		3.97
Appalachia	84		120		(36		)	13.80		19.32		NM
	$	141,860	$	121,648	$	20,212		$	67.91	$	67.33	$	0.58

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The following table provides an analysis of the change in our revenues for the three months ended September 30, 2014 compared to the three months ended September 30, 2013:

	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	30,849		$	(12,697	)	$	18,152
NGL	1,760			(182		)	1,578
Natural gas	(1,398		)	1,880			482
	$	31,211		$	(10,999	)	$	20,212

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 September 30, 2014 and 2013, we paid $7.6 million and $4.2 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
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Crude oil revenues as reported	$	118,716		$	100,564		$	18,152		18	%
Cash settlements of crude oil derivatives, net	(7,622		)	(4,649		)	(2,973		)	64	%
	$	111,094		$	95,915		$	15,179		16	%
Crude oil prices per Bbl, as reported	$	95.19		$	105.37		$	(10.19	)	(10	)%
Cash settlements of crude oil derivatives per Bbl	(6.11		)	(4.87		)	(1.23		)	25	%
	$	89.08		$	100.50		$	(11.42	)	(11	)%
Natural gas revenues as reported	$	13,354		$	12,872		$	482		4	%
Cash settlements of natural gas derivatives, net	65			484			(419		)	(87	)%
	$	13,419		$	13,356		$	63		—	%
Natural gas prices per Mcf, as reported	$	4.17		$	3.58		$	0.59		16	%
Cash settlements of natural gas derivatives per Mcf	0.02			0.13			(0.11		)	(85	)%
	$	4.19		$	3.71		$	0.47		13	%

Gain (Loss) on Sales of Property and Equipment

In the three months ended September 30, 2014, we recognized a gain of $63.0 million in connection with the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas.

Other Revenues

Other revenues, which includes includes gathering, transportation, compression, water supply and disposal fees that we charge to other parties, net of marketing and related expenses, decreased during the three months ended September 30, 2014 due primarily to lower throughput of unaffiliated natural gas production in the South and East Texas regions.

Production and Lifting Costs

	Three Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Lease operating	$	15,296	$	8,457	$	(6,839	)	(81	)%
Per unit of production ($/BOE)	$	7.32	$	4.68	$	(2.64	)	(56	)%

Lease operating expense increased during the three months ended September 30, 2014 due primarily to higher workover and subsurface maintenance expense of approximately $3 million in South and East Texas. All other costs, including chemical, water disposal and labor costs in the South Texas region, increased on an absolute basis attributable primarily to the expansion of operations. In addition, we incurred higher compression costs attributable to higher natural gas production in the South Texas region.

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	Three Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Gathering, processing and transportation	$	4,893	$	3,039	$	(1,854	)	(61	)%
Per unit of production ($/BOE)	$	2.34	$	1.68	$	(0.66	)	(39	)%

Higher natural gas and NGL production, primarily in our South Texas region resulted in an increase to gathering, processing and transportation expense during the three months ended September 30, 2014, partially offset by the effects of lower production volume in our East Texas region and the sale of our Mississippi assets in July 2014.

	Three Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	6,845		$	4,070		$	(2,775	)	(68	)%
Ad valorem taxes	845			2,527			1,682			67	%
	$	7,690		$	6,597		$	(1,093	)	(17	)%
Per unit production ($/BOE)	$	3.68		$	3.65		$	(0.03	)	(1	)%
Production/severance tax rate as a percent of product revenue	4.8		%	3.3		%

Production taxes increased during the three months ended September 30, 2014 due primarily to the higher level and concentration of crude oil production in the South Texas region, which carries a higher severance tax rate than our other operating areas.

General and Administrative

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

	Three Months Ended
	September 30,					Favorable
	2014			2013		(Unfavorable)			% Change
General and administrative expenses	$	10,580		$	10,420	$	(160	)	(2	)%
Share-based compensation (liability-classified)	(360		)	1,095		1,455			NM
Share-based compensation (equity-classified)	987			1,010		23			2	%
EF Acquisition-related arbitration and other costs	2			—		(2		)	NM
ERP system development costs	301			147		(154		)	NM
Restructuring expenses	17			5		(12		)	NM
	$	11,527		$	12,677	$	1,150		9	%
Per unit of production ($/BOE)	$	5.52		$	7.02	$	1.50		21	%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	5.22		$	5.85	$	0.63		11	%
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	5.06		$	5.77	$	0.71		12	%

On a unit of production basis, our general and administrative expenses, excluding liability and equity-classified share-based compensation, decreased during the three months ended September 30, 2014 compared to the 2013 period reflecting the benefit of the overall growth in scale of our operations as marginal increases in cost were spread over higher production volume. 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 the 2012 through 2014 PBRSU grants. The decrease 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 September 30, 2014 due primarily to fewer employees receiving grants. In the three months ended September 30, 2014, we incurred certain costs not eligible for capitalization, including post-implementation support and training with respect to our recently completed ERP system replacement.

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Exploration

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

	Three Months Ended
	September 30,					Favorable
	2014			2013		(Unfavorable)			% Change
Unproved leasehold amortization	$	1,808		$	3,759	$	1,951		52	%
Geological and geophysical costs	205			83		(122		)	NM
Other, primarily delay rentals	(27		)	115		142			123	%
	$	1,986		$	3,957	$	1,971		50	%

Unproved leasehold amortization decreased during the three months ended September 30, 2014 due primarily to a lower leasehold asset base subject to amortization in the 2014 period as compared to the 2013 period.

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
	September 30,					Favorable
	2014			2013		(Unfavorable)			% Change
DD&A expense	$	71,999		$	62,450	$	(9,549	)	(15	)%
DD&A rate ($/BOE)	$	34.47		$	34.57	$	0.10		—	%
	Production			Rates		Total
DD&A variance due to:	$	(9,746	)	$	197	$	(9,549	)

The effects of higher production volumes partially offset by marginally lower depletion rates were the primary factors attributable to the increase in DD&A.

Impairments

In September 2014, we recognized an oil and gas asset impairment of $6.1 million in connection with an exploration prospect drilled in the Mid-Continent region.

Interest Expense

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

	Three Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Interest on borrowings and related fees	$	22,559		$	22,754		$	195		1	%
Amortization of debt issuance costs	1,063			961			(102		)	(11	)%
Capitalized interest	(1,669		)	(3,497		)	(1,828		)	(52	)%
	$	21,953		$	20,218		$	(1,735	)	(9	)%
Weighted-average debt outstanding	$	1,120,500		$	1,178,000
Weighted average interest rate	8.43		%	8.05		%

Interest expense increased during the three months ended September 30, 2014 due primarily to lower capitalized interest in the current year period. The decrease resulted from the development of a significant portion of our proved undeveloped and unproved properties. The weighted-average interest rate increased marginally during the three months ended September 30, 2014 due primarily to the higher weighting of the 8.5% Senior Notes due 2020, or 2020 Senior Notes.

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Derivatives

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

	Three Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Oil and gas derivatives settled	$	(7,557	)	$	(4,165	)	$	(3,392	)	81	%
Oil and gas derivatives gain (loss)	74,014			(19,870		)	93,884			NM
	$	66,457		$	(24,035	)	$	90,492		80	%

We paid settlements of $7.6 million for crude oil derivatives and received settlements of less than $0.1 million for natural gas derivatives during the three months ended September 30, 2014 and paid settlements of $4.6 million for crude oil derivatives and received settlements of $0.4 million for natural gas derivatives during the three months ended September 30, 2013.

Other

The increase in other income is attributable to $1.3 million of interest received in connection with the arbitration settlement with MHR in the 2014 period.

Income Taxes

	Three Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Income tax (expense) benefit	$	(42,113	)	$	53,106		$	(95,219	)	NM
Effective tax rate	32.0		%	34.9		%

We recognized income tax expense for the three months ended September 30, 2014. The effective tax rate for the period includes federal taxes at the statutory rate of 35%, partially offset by state income tax effects which includes a deferred tax benefit associated with an expected decrease in the effective state income tax rate in future periods. The benefit is due primarily to a shift in the source of our expected future state taxable income as a result of the recent sale of all of our properties in Mississippi.

Due to operating losses incurred, we recognized an income tax benefit during the three months ended September 30,2013 which includes a deferred tax asset allowance for all state net operating losses.

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Nine Months EndedSeptember 30, 2014 Compared to the Nine Months EndedSeptember 30, 2013

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	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	3,292.4	2,226.0	1,066.4		12,060.2	8,153.9	3,906.3		48	%
East Texas	40.1	47.0	(6.9	)	146.9	172.3	(25.4	)	(15	)%
Mid-Continent	104.2	128.2	(24.0	)	381.7	469.7	(88.0	)	(19	)%
Mississippi	5.5	10.0	(4.5	)	20.1	36.8	(16.6	)	(45	)%
Appalachia	—	0.1	(0.1	)	—	0.5	(0.5	)	(100	)%
	3,442.2	2,411.5	1,030.8		12,608.9	8,833.2	3,775.8		43	%

NGLs	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	543.3	355.6	187.7		1,990.1	1,302.6	687.5		53	%
East Texas	92.2	154.6	(62.4	)	337.6	566.3	(228.7	)	(40	)%
Mid-Continent	160.4	238.1	(77.7	)	587.5	872.0	(284.5	)	(33	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	—	—		—	—	—		—	%
	795.8	748.3	47.6		2,915.2	2,740.9	174.3		6	%

Natural gas	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	2,829	1,798	1,031		10.4	6.6	3.8		57	%
East Texas	3,065	3,460	(395	)	11.2	12.7	(1.4	)	(11	)%
Mid-Continent	1,968	2,205	(238	)	7.2	8.1	(0.9	)	(11	)%
Mississippi	2,442	3,360	(918	)	8.9	12.3	(3.4	)	(27	)%
Appalachia	109	110	(1	)	0.4	0.4	—		(1	)%
	10,412	10,933	(521	)	38.1	40.0	(1.9	)	(5	)%

Combined total	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	4,307	2,881	1,426		15,777.4	10,554.4	5,223.0		49	%
East Texas	643	778	(135	)	2,355.5	2,850.7	(495.2	)	(17	)%
Mid-Continent	593	734	(141	)	2,170.6	2,688.1	(517.6	)	(19	)%
Mississippi	412	570	(158	)	1,510.9	2,087.9	(577.0	)	(28	)%
Appalachia	18	18	—		66.4	67.6	(1.2	)	(2	)%
	5,973	4,982	992		21,880.8	18,248.8	3,632.0		20	%

Total production increased during the nine months ended September 30, 2014 compared to the corresponding period of 2013 due primarily to production from the continued expansion of our Eagle Ford development program in South Texas. The increase was partially offset by natural production declines in our East Texas, Mid-Continent and Mississippi regions as well as the effect of the sale of our Mississippi properties in July 2014. Approximately 71 percent of total production during the nine months ended September 30, 2014 was attributable to oil and NGLs, which represents an increase of approximately 34 percent over the prior year period. During the nine months ended September 30, 2014, our Eagle Ford production represented

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approximately 72 percent of our total production compared to approximately 58 percent from this play during the corresponding period of 2013.

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	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	322,429	$	232,771	$	89,658		$	97.93	$	104.57	$	(6.64	)
East Texas	3,929		4,736		(807		)	97.99		100.70		(2.71		)
Mid-Continent	9,496		11,895		(2,399		)	91.12		92.76		(1.64		)
Mississippi	528		1,075		(547		)	96.02		107.09		(11.08		)
Appalachia	—		12		(12		)	—		—		—
	$	336,382	$	250,489	$	85,893		$	97.72	$	103.87	$	(6.15	)

NGLs	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	14,721	$	9,134	$	5,587		$	27.10	$	25.68	$	1.42
East Texas	4,412		5,090		(678		)	47.88		32.93		14.95
Mid-Continent	8,067		8,428		(361		)	50.30		35.40		14.90
Mississippi	—		—		—			—		—		—
Appalachia	—		—		—			—		—		—
	$	27,200	$	22,652	$	4,548		$	34.18	$	30.27	$	3.91

Natural gas	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	12,446	$	6,573	$	5,873		$	4.40	$	3.66	$	0.74
East Texas	14,268		11,576		2,692			4.66		3.35		1.31
Mid-Continent	9,257		8,775		482			4.70		3.98		0.73
Mississippi	11,496		12,549		(1,053		)	4.71		3.74		0.97
Appalachia	392		992		(600		)	3.61		NM		NM
	$	47,859	$	40,465	$	7,394		$	4.60	$	3.70	$	0.90

Combined total	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	349,596	$	248,478	$	101,118		$	81.16	$	86.24	$	(5.08	)
East Texas	22,609		21,402		1,207			35.16		27.50		7.66
Mid-Continent	26,820		29,098		(2,278		)	45.26		39.65		5.61
Mississippi	12,024		13,624		(1,600		)	29.15		23.90		5.25
Appalachia	392		1,004		(612		)	21.63		NM		NM
	$	411,441	$	313,606	$	97,835		$	68.88	$	62.95	$	5.93

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The following table provides an analysis of the change in our revenues for the nine months ended September 30, 2014 compared to the nine months ended September 30, 2013:

	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	107,073		$	(21,180	)	$	85,893
NGL	1,442			3,106			4,548
Natural gas	(1,928		)	9,322			7,394
	$	106,587		$	(8,752	)	$	97,835

Effects of Derivatives

As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. In the nine months ended September 30, 2014 and 2013, we paid $17.8 million and received $1.6 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: 

	Nine Months Ended
	September 30,					Favorable
	2014			2013		(Unfavorable)			% Change
Crude oil revenues, as reported	$	336,382		$	250,489	$	85,893		34	%
Cash settlements of crude oil derivatives, net	(15,987		)	628		(16,615		)	NM
	$	320,395		$	251,117	$	69,278		28	%
Crude oil prices per Bbl, as reported	$	97.72		$	103.87	$	(6.15	)	(6	)%
Cash settlements of crude oil derivatives per Bbl	(4.64		)	0.26		(4.90		)	NM
	$	93.08		$	104.13	$	(11.05	)	(11	)%
Natural gas revenues, as reported	$	47,859		$	40,465	$	7,394		18	%
Cash settlements of natural gas derivatives, net	(1,849		)	997		(2,846		)	NM
	$	46,010		$	41,462	$	4,548		11	%
Natural gas prices per Mcf, as reported	$	4.60		$	3.70	$	0.90		24	%
Cash settlements of natural gas derivatives per Mcf	(0.18		)	0.09		(0.27		)	NM
	$	4.42		$	3.79	$	0.63		17	%

Gain (Loss) on Sales of Property and Equipment

In the nine months ended September 30, 2014, we recognized a gain of $63.0 million in connection with the sale of rights to construct a crude oil gathering and intermediate transportation system and a gain of $57.0 million on the sale of our natural gas gathering and gas lift assets in South Texas, including $56.7 million recognized upon the closing of the sale and $0.3 million attributable to the amortization of the deferred portion of the gain.

Other Revenues

Other revenues, which includes gathering, transportation, compression, water supply and disposal fees that we charge to other parties, net of marketing and related expenses, increased during the nine months ended September 30, 2014 due primarily to income related to water supply and disposal which began in April 2014.

Production and Lifting Costs

	Nine Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Lease operating	$	38,103	$	24,891	$	(13,212	)	(53	)%
Per unit of production ($/BOE)	$	6.38	$	5.00	$	(1.38	)	(28	)%

Lease operating expense increased during the nine months ended September 30, 2014 due primarily to higher workover and subsurface maintenance costs of approximately $8 million in South and East Texas. All other costs, including chemical, water disposal and labor costs associated primarily with the expansion of operations in the South Texas region, increased on an

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absolute basis. In addition we incurred higher compression costs attributable to higher natural gas production in South Texas. As discussed in Key Developments, we sold our natural gas gathering and gas lift assets in the South Texas region and entered into an agreement with the buyer to provide us natural gas gathering, compression and gas lift services. We began incurring costs for these services in February 2014.

	Nine Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Gathering, processing and transportation	$	11,380	$	9,598	$	(1,782	)	(19	)%
Per unit of production ($/BOE)	$	1.91	$	1.93	$	0.02		1	%

Gathering, processing and transportation charges increased on an absolute basis during the nine months ended September 30, 2014 due primarily to gathering charges for natural gas and NGL production in the South Texas region attributable to the new gathering, compression and gas lift services agreement discussed above, offset partially by the effect of lower natural gas and NGL production volume in our East Texas, Mid-Continent and Mississippi regions.

	Nine Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	18,739		$	12,762		$	(5,977	)	(47	)%
Ad valorem taxes	3,766			6,770			3,004			44	%
	$	22,505		$	19,532		$	(2,973	)	(15	)%
Per unit production ($/BOE)	$	3.77		$	3.92		$	(0.03	)	(1	)%
Production/severance tax rate as a percent of product revenue	4.6		%	4.1		%

Production taxes increased during the nine months ended September 30, 2014 due primarily to the higher level and concentration of crude oil production in the South Texas region, which carries a higher severance tax rate than our other operating areas, partially offset by severance tax audit refunds for natural gas production in Mississippi.

General and Administrative

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

	Nine Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
General and administrative expenses	$	32,125	$	30,378	$	(1,747	)	(6	)%
Share-based compensation (liability-classified)	6,632		1,544		(5,088		)	NM
Share-based compensation (equity-classified)	2,638		4,781		2,143			45	%
EF Acquisition-related transaction costs	—		2,396		2,396			NM
EF Acquisition-related arbitration and other costs	589		—		(589		)	NM
ERP system development costs	1,045		319		(726		)	NM
Restructuring expenses	26		5		(21		)	NM
	$	43,055	$	39,423	$	(3,632	)	(9	)%
Per unit of production ($/BOE)	$	7.21	$	7.91	0.70			9	%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	5.66	$	6.64	0.98			15	%
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	5.38	$	6.10	0.72			12	%

On a unit of production basis, our general and administrative expenses, excluding liability and equity-classified share-based compensation, decreased during the nine months ended September 30, 2014 compared to the 2013 period, reflecting the benefit of the overall growth in scale of our operations as marginal increases in cost were spread over higher production volume. Liability-classified share-based compensation is attributable to our PBRSUs, and represents mark-to-market charges associated with the increase in fair value of the 2012 through 2014 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 nine months ended September 30, 2014 due primarily to fewer employees receiving grants and the elimination of retirement age-eligible, or grant-date vesting provisions. In 2013, we incurred transaction costs associated with the EF Acquisition, including advisory, legal, due diligence and other professional fees. In 2014, we incurred costs including legal and

33

litigation support fees attributable to our arbitration with MHR with respect to the EF Acquisition transaction. In the nine months ended September 30, 2014, we also incurred certain costs not eligible for capitalization, including post-implementation support and training with respect to our recently completed ERP system replacement. Similar charges incurred during the prior year period include preliminary project analysis and other non-capitalizable costs.

Exploration

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

	Nine Months Ended
	September 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Unproved leasehold amortization	$	8,387	$	14,167	$	5,780		41	%
Geological and geophysical costs	4,785		2,880		(1,905		)	(66	)%
Other, primarily delay rentals	823		1,050		227			22	%
	$	13,995	$	18,097	$	4,102		23	%

Unproved leasehold amortization decreased during the nine months ended September 30, 2014 due primarily to the classification of our unproved property in the Eagle Ford 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 due to higher seismic data acquisition costs attributable to our development program in the South Texas region along with an ongoing exploration effort in the 2014 period. Delay rentals decreased as the prior year period included charges attributable to undeveloped acreage acquired in connection with the EF Acquisition.

Depreciation, Depletion and Amortization (DD&A)

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

	Nine Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
DD&A expense	$	215,623		$	178,355		$	(37,268	)	(21	)%
DD&A rate ($/BOE)	$	36.10		$	35.80		$	(0.30	)	(1	)%
	Production			Rates			Total
DD&A variance due to:	$	(35,478	)	$	(1,790	)	$	(37,268	)

Higher overall production volumes as well as higher depletion rates associated with oil and NGL production were the primary factors affecting the increase in DD&A expense. Our average DD&A rate increased slightly due to the higher proportion of capitalized finding and development costs attributable to our drilling program in the Eagle Ford.

Impairments

In September 2014, we recognized an oil and gas asset impairment of $6.1 million in connection with an exploration prospect drilled in the Mid-Continent region. In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets in Mississippi. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 to write these assets down to fair value. The sale was completed in July 2014.

Interest Expense

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

	Nine Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Interest on borrowings and related fees	$	69,477		$	57,239		$	(12,238	)	(21	)%
Accretion of original issue discount	—			431			431			100	%
Amortization of debt issuance costs	3,114			2,415			(699		)	(29	)%
Capitalized interest	(4,875		)	(3,580		)	1,295			36	%
	$	67,716		$	56,505		$	(11,211	)	(20	)%
Weighted-average debt outstanding	$	1,237,538		$	953,038
Weighted average interest rate	7.82		%	8.41		%

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Interest expense increased during the nine months ended September 30, 2014 due primarily to higher weighted-average debt outstanding following the issuance of the 2020 Senior Notes in April 2013 and higher average outstanding borrowings under the Revolver. 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 10.375% Senior Notes due 2016, or the 2016 Senior Notes, which were retired in connection with the tender offer and the redemption in May 2013. The weighted-average interest rate declined during the nine months ended September 30, 2014 due primarily to the replacement of the 2016 Senior Notes with the 2020 Senior Notes as well as borrowings under the Revolver, both of which carry lower interest rates.

Loss on Extinguishment of Debt

In May 2013, we completed the tender offer for, and the redemption of, all of the 2016 Senior Notes. We paid a total of $330.9 million including consent payments and accrued interest and recognized a loss on extinguishment of debt of $29.2 million. The loss on extinguishment of debt included non-cash charges of $10.0 million attributable to the write-off of unamortized debt issuance costs and the remaining debt discount associated with the 2016 Senior Notes.

Derivatives

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

	Nine Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Oil and gas derivatives settled	$	(17,836	)	$	1,625		$	(19,461	)	NM
Oil and gas derivatives gain (loss)	25,966			(24,833		)	50,799			NM
	$	8,130		$	(23,208	)	$	31,338		NM

We paid settlements of $16.0 million for crude oil derivatives and $1.8 million for natural gas derivatives during the nine months ended September 30, 2014 and received settlements of $0.6 million from crude oil derivatives and $1.0 million from natural gas derivatives during the nine months endedSeptember 30, 2013.

Other

The increase in other income is substantially attributable to $1.3 million of interest received in connection with the arbitration settlement with MHR.

Income Taxes

	Nine Months Ended
	September 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Income tax benefit	$	339		$	75,577		$	(75,238	)	(100	)%
Effective tax benefit rate	4.4		%	34.9		%

We recognized an income tax benefit for the nine months ended September 30, 2014. The annual effective tax rate applied to the nine months ended September 30, 2014 includes federal taxes at the statutory rate of 35%; however, the federal effect is almost entirely offset by state income tax effects, which include a deferred tax benefit associated with an expected decrease in the effective state income tax rate in future periods. The benefit is due primarily to a shift in the source of our expected future state taxable income as a result of the recent sale of all of our properties in Mississippi. Our effective tax rate also 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 asset.

Due to the loss incurred during the nine months endedSeptember 30, 2013, we recognized income tax benefit. The income tax benefit included the effect of a deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.

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Financial Condition

Liquidity

Our primary sources of liquidity include cash on hand, cash from operating activities, borrowings under the Revolver, proceeds from the sales of 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 other factors.

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 impacts our cash from operating activities, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our remaining 2014 capital program with cash on hand, cash from operating activities and, if necessary, borrowings under the Revolver. We have no debt maturities until September 2017 when the Revolver matures. We believe that our cash on hand, cash from operating activities and borrowing capacity under the Revolver will be sufficient to meet our debt service, preferred stock dividend and working capital requirements, as well as our anticipated capital expenditures. In view of our depressed share price and to expand our capital allocation options, we will see an amendment to the Revolver to permit us to repurchase our common stock under appropriate circumstances. Based on the level of cash on hand as of September 30, 2014 and our projected production and current plans for capital expenditures in the Eagle Ford, excluding any potential share repurchases, we anticipate that we will not borrow any amounts under the Revolver until some time in the first quarter of 2015.

Capital Resources

In 2014, we anticipate making capital expenditures, excluding acquisitions, of up to approximately $800 million. Based on expenditures to date and forecasted activity for the remainder of 2014, we expect to allocate a substantial portion of our capital expenditures to the Eagle Ford. This allocation includes approximately 80 percent for drilling and completions, 16 percent for leasehold acquisition and four percent for facilities and other projects. The total forecasted activity assumes a drilling program utilizing eight operated drilling rigs in the Eagle Ford. We continually review drilling and other capital expenditure plans and may change the amount we spend, or the allocations, 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 on Hand and Cash From Operating Activities. As of September 30, 2014, we had approximately $124 million of cash on hand which was substantially derived from the proceeds received from asset sales in July 2014. We utilized those proceeds to fully pay down our outstanding borrowings under the Revolver. Accordingly, we anticipate drawing from this cash balance and cash provided from operating activities for the remainder of 2014 to fund our planned capital expenditures, scheduled interest payments on our outstanding senior notes, preferred stock dividends and working capital requirements.

In addition to commodity price volatility, as discussed in detail below, our cash from operating activities is impacted by the timing of our working capital requirements. The most significant component thereof is attributable to the timing of payments made for drilling and completion capital expenditures and the related billing and collection of amounts from our partners. This can be substantial to the extent that we are the operator of lower working interest wells. In certain circumstances, we have and will continue to utilize capital cash calls to mitigate our related working capital burden.

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 nine months ended September 30, 2014, our commodity derivatives portfolio resulted in $16.0 million of net cash payments related to higher than anticipated prices received for our crude oil production and $1.8 million of net cash payments attributable to higher than anticipated prices received for our natural gas production. As we began to experience in the three months ended September 30, 2014, commodity prices have continued a downward trend. Accordingly, we anticipate that our derivative portfolio will result in receipts from settlements for the next several months.

We have hedged approximately 13,000 barrels of daily crude oil production, or approximately 77 percent of our estimated crude oil production for the remainder of 2014, at a weighted-average floor/swap price of $92.92 per barrel. For 2015, we have hedged approximately 12,000 barrels of daily crude oil production at weighted-average floor/swap prices of $90.20 per barrel. For 2016, we have hedged approximately 3,000 barrels of daily crude oil production at weighted-average floor/swap prices of $90.84 per barrel. We have also hedged 5,000 million British Thermal Units, or MMBtu, of daily natural gas production, or approximately 13 percent of our estimated natural gas production for the remainder of 2014 at a weighted-average floor/swap price of $4.50 per MMBtu. For the first quarter of 2015, we have hedged 5,000 MMBtu of daily natural gas production at a weighted-average floor/swap price of $4.50 per MMBtu.

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Revolver Borrowings. The Revolver provides for a $450 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $150 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. Upon the closing of the sale of our Selma Chalk assets in July 2014, the borrowing base was reduced by $37.5 million from $475 million to $437.5 million. In October 2014, the borrowing base was increased to $500 million in connection with the regular semi-annual redetermination. The next semi-annual redetermination is scheduled for May 2015. In addition, the Revolver was amended to clarify the requirements with respect to pro forma treatment of material acquisitions and dispositions for purposes of the leverage ratio covenant under the Revolvert. 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 million outstanding as of September 30, 2014. As of September 30, 2014, our available borrowing capacity under the Revolver was $435.8 million.

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

	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended September 30, 2014	$	42,446	$	130,000	1.8853	%
Nine months ended September 30, 2014	$	170,802	$	407,000	2.2503	%

Proceeds from Sales of Assets. In July 2014, we received approximately $147 million and $67 million, net of transaction costs, from the sale of rights to construct an oil gathering system in South Texas and the sale of our Selma Chalk assets in Mississippi, respectively. In January 2014, we sold our natural gas gathering and gas lift assets in South Texas for proceeds of approximately $96 million, net of closing costs and adjustments. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-strategic undeveloped acreage, among others.

Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we consider capital market transactions, including the offering of debt and equity securities. Historically, we have entered into such transactions to facilitate acquisitions and to pursue opportunities to adjust our total capitalization. For a detailed analysis of our historical proceeds from capital markets transactions, including the Series B Preferred Stock and the 2020 Senior Notes, see the Cash Flows discussion that follows.

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Cash Flows

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

	Nine Months Ended
	September 30,
	2014			2013			Variance
Cash flows from operating activities
Operating cash flows, net	$	300,744		$	226,754		$	73,990
Working capital changes (excluding interest and income taxes), net	(35,840		)	21,988			(57,828		)
Commodity derivative settlements (paid) received, net:
Crude oil	(15,987		)	628			(16,615		)
Natural gas	(1,849		)	997			(2,846		)
Interest payments, net of amounts capitalized	(42,903		)	(20,671		)	(22,232		)
Income taxes paid	(100		)	—			(100		)
Acquisition arbitration, transaction and other costs paid	(589		)	(2,396		)	1,807
ERP system development costs paid	(1,045		)	(319		)	(726		)
Restructuring and exit costs paid	(1,981		)	(2,147		)	166
Net cash provided by operating activities	200,450			224,834			(24,384		)
Cash flows from investing activities
Acquisition and working capital-related settlements, net	33,712			(401,262		)	434,974
Capital expenditures – property and equipment	(545,031		)	(356,964		)	(188,067		)
Proceeds from sales of assets, net	311,913			653			311,260
Net cash used in investing activities	(199,406		)	(757,573		)	558,167
Cash flows from financing activities
Proceeds from the issuance of preferred stock, net	313,330			—			313,330
Payments made to induce conversion of preferred stock	(4,256		)	—			(4,256		)
Proceeds from the issuance of senior notes	—			775,000			(775,000		)
Retirement of senior notes	—			(319,090		)	319,090
Proceeds (repayments) from revolving credit facility borrowings, net	(206,000		)	128,000			(334,000		)
Debt issuance costs paid	(151		)	(25,199		)	25,048
Dividends paid on preferred stock	(5,165		)	(5,137		)	(28		)
Other, net	1,414			(164		)	1,578
Net cash provided by financing activities	99,172			553,410			(454,238		)
Net increase in cash and cash equivalents	$	100,216		$	20,671		$	79,545

Cash Flows From Operating Activities. Crude oil and NGL production with higher operating profit resulted in higher operating cash flows during the nine months ended September 30, 2014 compared to the corresponding period in 2013; however, this increase was offset to some extent by the higher working capital requirements of our expanded drilling program. Specifically, during 2014, we began drilling several wells with lower working interests resulting in significantly larger payments for drilling and completion costs and larger corresponding receivables from our joint interest partners when compared to the prior year period. In addition, our commodity derivatives portfolio generated net payments during the 2014 period as compared to net receipts during the 2013 period due primarily to realized crude oil and natural gas prices exceeding hedged prices. Due primarily to the issuance of the 2020 Senior Notes in 2013 and higher average outstanding borrowings under the Revolver, we had significantly higher interest payments during the 2014 period.

Cash Flows From Investing Activities. Capital expenditures were substantially higher during the nine months ended September 30, 2014 compared to the corresponding period during 2013 due primarily to a higher level of drilling activity and lease acquisitions in the Eagle Ford.

Our capital expenditures during the 2014 period were partially offset by the receipt of net proceeds from the sale of assets, including approximately $147 million from the sale of rights to construct an oil gathering and intermediate transportation system in South Texas in July 2014, approximately $68 million from the sale of our Selma Chalk assets in Mississippi in July 2014 and approximately $96 million from the sale of our natural gas gathering and gas lift assets in South Texas in January 2014. A portion of those proceeds was used to pay down outstanding borrowings under the Revolver. We also received approximately $35 million in August 2014 with respect to the resolution of arbitration matters in connection with the EF Acquisition. Approximately $34 million, net of interest income on the settlement, was classified as an investing activity. Net

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proceeds from asset sales 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.

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

	Nine Months Ended
	September 30,
	2014		2013
Oil and gas:
Drilling and completion	$	438,150	$	314,748
Lease acquisitions and other land-related costs 1	99,917		29,517
Geological and geophysical (seismic) costs	4,785		2,880
Pipeline, gathering facilities and other equipment	12,634		11,436
	555,486		358,581
Other – Corporate 2	1,287		2,137
Total capital program costs	$	556,773	$	360,718

______________________

¹ Includes site preparation and other pre-drilling costs.

² Includes approximately $0.8 million in 2014 and $1.2 million in 2013 for an integrated enterprise-wide information technology platform.

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:

	Nine Months Ended
	September 30,
	2014			2013
Total capital program costs	$	556,773		$	360,718
Increase in accrued capitalized costs	(12,805		)	(5,725		)
Less:
Exploration costs charged to operations:
Geological and geophysical (seismic)	(4,785		)	(2,880		)
Other, primarily delay rentals	(823		)	(1,050		)
Transfers from tubular inventory and well materials	(35		)	(1,126		)
Add:
Tubular inventory and well materials purchased in advance of drilling	1,831			3,447
Capitalized interest	4,875			3,580
Total cash paid for capital expenditures	$	545,031		$	356,964

Cash Flows From Financing Activities. In June 2014, we issued the Series B Preferred Stock for net proceeds of approximately $313 million. Cash flows from financing activities for the nine months ended September 30, 2014 also included net repayments under the Revolver, funded primarily with proceeds from the issuance of Series B Preferred Stock and asset sales, while the 2013 period includes net borrowings under the Revolver, which were used to finance a portion of our capital program. In June and July of 2014, we paid a total of $4.3 million to induce the conversion of approximately 30 percent of the outstanding shares of the Series A Preferred Stock. Both the 2014 and 2013 periods included dividends paid on the Series A Preferred Stock. In April 2013, we issued the 2020 Senior Notes, the proceeds of which were used to fund the EF Acquisition and a portion of the tender offer and the redemption of the 2016 Senior Notes. We incurred and paid costs in the 2014 and 2013 periods associated with amendments to the Revolver in advance of the Series B Preferred Stock and the 2020 Senior Notes offering transactions as well as costs paid in the 2013 period associated with the issuance of the 2020 Senior Notes. We also received proceeds of $1.4 million during the 2014 period from the exercise of stock options.

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Capitalization

The following table summarizes our total capitalization as of the dates presented:

	September 30,			December 31,
	2014			2013
Revolving credit facility	$	—		$	206,000
Senior notes due 2019	300,000			300,000
Senior notes due 2020	775,000			775,000
Total debt	1,075,000			1,281,000
Shareholders' equity 1	1,098,667			788,804
	$	2,173,667		$	2,069,804
Debt as a % of total capitalization	49		%	62		%

_____________________

¹ Includes 7,945 and 11,500 shares of the Series A Preferred Stock as of September 30, 2014 and December 31, 2013, respectively, and 32,500 shares of the Series B Preferred Stock as of September 30, 2014. Both series of preferred stock have a liquidation preference of $10,000 per share representing a total of $404 million and $115 million as of September 30, 2014 and December 31, 2013, respectively.

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%, plus, in each case, 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 September 30, 2014, the actual interest rate applicable to the Revolver was 1.6875% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.50%. 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 September 30, 2014, commitment fees were being charged at a rate of 0.375%.

The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries, or 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.

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.

Series A Preferred Stock. The annual dividend on each share of the Series A 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 Series A 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 Series A Preferred Stock. The initial conversion price represents a premium of 20 percent relative to the October 2012 common stock offering price of $5.00 per share. The Series A Preferred Stock is not redeemable for cash 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 Series A 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 Series A 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 nine months ended September 30, 2014, a total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5.9 million shares of common stock.

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Series B Preferred Stock. The annual dividend on each share of the Series B 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 Series B 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 $18.34 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 545.17 shares of our common stock for each share of the Series B Preferred Stock. The initial conversion price represents a premium of 30 percent relative to the last reported sales price of $14.11 per common share prior to the offering of the Series B Preferred Stock. The Series B Preferred Stock is not redeemable for cash by us or the holders at any time. At any time on or after July 15, 2019, we may, at our option, cause all outstanding shares of the Series B 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 Series B 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.

Covenant Compliance. The Revolver and the indentures governing 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 other requirements. As of September 30, 2014 and through the date upon which our Condensed Consolidated Financial Statements were issued, we were in compliance with these covenants.

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, any 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 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 4.25 to 1.0 for periods through December 31, 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.

The indentures governing our senior notes include an incurrence test which is determined by an interest coverage ratio, as defined in the indentures. The interest coverage ratio may not be less than 2.25 times consolidated EBITDAX, a non-GAAP measure.

As of September 30, 2014 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 September 30, 2014:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.25 to 1	2.6 to 1
Current ratio	> 1.00 to 1	2.8 to 1
Interest coverage	> 2.25 to 1	3.7 to 1

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. 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.

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New Accounting Standards

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers, orASU 2014-09, which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014-09 on our ongoing financial reporting.

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

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 September 30, 2014, however, we had no borrowings under the Revolver.

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 September 30, 2014, our commodity derivative portfolio was in a net asset position. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with two 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.

During the nine months ended September 30, 2014, we reported net commodity derivative gains of $8.1 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 September 30, 2014:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2014	Collars	2,000	$	90.00	$	94.33	$	264	$	—
First quarter 2015	Collars	4,000	$	87.50	$	94.66	649		—
Second quarter 2015	Collars	4,000	$	87.50	$	94.66	947		—
Third quarter 2015	Collars	3,000	$	86.67	$	94.73	770		—
Fourth quarter 2015	Collars	3,000	$	86.67	$	94.73	838		—
Fourth quarter 2014	Swaps	11,000	$	93.45			3,301		40
First quarter 2015	Swaps	9,000	$	91.81			2,197		—
Second quarter 2015	Swaps	9,000	$	91.81			2,835		—
Third quarter 2015	Swaps	8,000	$	91.06			2,352		—
Fourth quarter 2015	Swaps	8,000	$	91.06			2,432		—
First quarter 2016	Swaps	3,000	$	90.84			1,176		—
First quarter 2016	Swaps	3,000	$	90.84			1,284		—
First quarter 2016	Swaps	3,000	$	90.84			1,395		—
First quarter 2016	Swaps	3,000	$	90.84			1,447		—
First quarter 2015	Swaptions	1,000	$	88.00			—		252
Second quarter 2015	Swaptions	1,000	$	88.00			—		251
Third quarter 2015	Swaptions	1,000	$	88.00			—		251
Fourth quarter 2015	Swaptions	1,000	$	88.00			—		251
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2014	Swaps	5,000	$	4.50			185		—
First quarter 2015	Swaps	5,000	$	4.50			129		—
Settlements to be received in subsequent period							52		—

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	$	(65.2	)	$	61.8
Effect on the fair value of natural gas derivatives	$	(0.8	)	$	0.8
Effect on the remainder of 2014 operating income, excluding crude oil derivatives	$	12.9		$	(12.9	)
Effect on the remainder of 2014 operating income, excluding natural gas derivatives	$	2.9		$	(2.9	)

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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 September 30, 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 September 30, 2014, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2014, no changes were made in our internal control over financial reporting 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 1 Legal Proceedings

Commencing December 2013, we were involved in arbitration with MHR, the seller in the EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. In July 2014, we received the arbitrator’s determination, which required MHR to pay us a total of $35.1 million including purchase price adjustments, revenue suspense funds due to partners and royalty owners and interest ($1.3 million) on the funds since the date of acquisition. Payment of the arbitration settlement was made by MHR in August 2014.

Item 6 Exhibits

(10.1)	Construction and Field Gathering Agreement dated July 30, 2014 by and between Penn Virginia Oil & Gas, L.P. and Republic Midstream, LLC.
(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

45

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
October 29, 2014	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)

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EX-10.1

EXECUTION VERSION

CONSTRUCTION AND FIELD GATHERING AGREEMENT

by and between

REPUBLIC MIDSTREAM, LLC

(“Gatherer”)

and

PENN VIRGINIA OIL & GAS, L.P.

(“Shipper”)

Dated July 30, 2014

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS1

ARTICLE II DEDICATION AND COMMITMENT                    6

ARTICLE III CONSTRUCTION AND OWNERSHIP OF THE GATHERING SYSTEM; CONSTRUCTION SCHEDULE                                8

ARTICLE IV CHARACTERISTICS OF THE GATHERING SYSTEM            10

ARTICLE V QUANTITY, NOMINATION AND IMBALANCE PROCEDURES    12

ARTICLE VI CONTROL OF OIL                                12

ARTICLE VII MEASUREMENT AND TESTING                        13

ARTICLE VIII QUALITY                                    13

ARTICLE IX MINIMUM VOLUME COMMITMENTS; FEES                14

ARTICLE X TERM                                        15

ARTICLE XI STATEMENTS AND PAYMENTS                        15

ARTICLE XII REGULATION                                15

ARTICLE XIII TAXES AND ROYALTIES                            16

ARTICLE XIV REPRESENTATIONS AND WARRANTIES                17

ARTICLE XV EASEMENTS                                    18

ARTICLE XVI INDEMNITY                                    18

ARTICLE XVII NOTICES AND STATEMENTS                        19

ARTICLE XVIII FORCE MAJEURE                                20

ARTICLE XIX CONFIDENTIAL INFORMATION                        21

ARTICLE XX ASSIGNMENT OF GATHERING SYSTEM                22

ARTICLE XXI MISCELLANEOUS                                22

EXHIBITS

EXHIBIT A    DEDICATION AREA

EXHIBIT B    NOMINATION PROCEDURES

EXHIBIT C    MEASUREMENT AND TESTING

EXHIBIT D    REQUIRED INSURANCE

EXHIBIT E    FORM OF MEMORANDUM OF DEDICATION - GONZALES

EXHIBIT F     FORM OF MEMORANDUM OF DEDICATION - LAVACA

EXHIBIT G     DESIGN PROPOSAL

EXHIBIT H    FORM OF TARIFF

EXHIBIT I    FORM OF MEMORANDUM OF DEDICATION - FAYETTE

CONSTRUCTION AND FIELD GATHERING AGREEMENT

THIS CONSTRUCTION AND FIELD GATHERING AGREEMENT (this “Agreement”) is made and entered into this 30th day of July, 2014 (the “Effective Date”) by and between Republic Midstream, LLC, a Delaware limited liability company (“Gatherer”), and Penn Virginia Oil & Gas, L.P., a Texas limited partnership (“Shipper”). Gatherer and Shipper may hereinafter be referred to singularly as a “Party” and, together, as the “Parties.”

WITNESSETH:

WHEREAS, the Parties desire that Gatherer construct, own and operate certain crude oil gathering lines to gather Shipper’s Oil (as defined in Article I) within the Dedication Area (as defined in Article I) and to deliver Shipper’s Oil to the Delivery Points (as defined in Article I); and

WHEREAS, Shipper desires to have Shipper’s Oil within the Dedication Area gathered by Gatherer and delivered to the Delivery Points;

NOW, THEREFORE, in consideration of the mutual covenants, terms and conditions herein contained, together with other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, and intending to be legally bound hereby, the Parties, for themselves and for their successors and assigns, do hereby mutually covenant and agree as follows:

ARTICLE I

DEFINITIONS

For the purposes of this Agreement, the following terms are defined as follows:

“Acreage Swap” has the meaning given such term in Section 2.8.

“Additional Segment” means the Crude Oil gathering pipelines and other related facilities and equipment located in the Dedication Area necessary to gather and transport Crude Oil from a Receipt Point to any existing portion of the Gathering System.

“Additional Units” has the meaning given such term in Section 3.3(c).

“Affiliate” means, with respect to any Person, any other Person controlling, controlled by or under common control with such Person. For purposes of this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person.

“Agreement” has the meaning given such term in the introductory paragraph hereto.

“API” means the American Petroleum Institute

“API Gravity” means a gravity (at sixty degrees (60°) Fahrenheit) determined in accordance with the specific gravity scale developed by the API and expressed in degrees.

“Applicable Law” means, with respect to any Person, all laws, statutes, codes, acts, treaties, ordinances, orders, judgments, writs, decrees, injunctions, rules, regulations, governmental approvals, licenses and permits, directives and requirements of all Governmental Authorities, including all official interpretations thereof by any such Governmental Authorities, as in effect at any time or from time to time and, in each case, applicable to or binding upon such Person and, in the case of Gatherer, Gatherer’s ownership, use and operation of the Gathering System.

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“Barrel” means a standard barrel of 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons corrected to sixty degrees (60°) Fahrenheit and equilibrium vapor pressure.

“Base Gathering System” means the Crude Oil gathering pipelines and other related facilities and equipment located in the Dedication Area necessary to gather and transport Crude Oil from the Receipt Points in the Core Units to the pipeline inlet flanges at the CDP; provided, however, that the Base Gathering System shall not include any trucking services.

“CDP” means the central delivery point identified on the map attached hereto as Exhibit A.

“Change in Law” means any change to any Applicable Law in effect on the Effective Date.

“Claim” means any demand, claim, action, suit, legal proceeding (whether at law or in equity) or arbitration.

“Collateral Assignment” has the meaning given such term in Section 20.1.

“Completion Date” has the meaning given such term in Section 3.5.

“Confidential Information” means (i) the terms and conditions of this Agreement, (ii) the terms and conditions of Shipper’s gathering and/or transportation agreements with downstream pipelines, trucking company or purchasers and (iii) all information and data (including all copies thereof) that is furnished or submitted by any Party or its Affiliates, whether oral, written or electronic, to the other Party or its Affiliates in connection with the operation of the Gathering System or the services rendered by Gatherer hereunder, including customer, pricing and nomination information and the terms and conditions of any contracts to which such furnishing Party is a party. Notwithstanding the foregoing, the term “Confidential Information” shall not include any information that a claiming Party proves:

(a)is in the public domain at the time of its disclosure, other than as a result of a breach of this Agreement;

(b)was in the possession of any Party or any of its Affiliates prior to being furnished such information; or

(c)has been independently acquired or developed by a Party or any of its Affiliates without breaching this Agreement.

“Connection Units” means the Core Units and any Additional Units connected to the Gathering System.

“Construction Notice” has the meaning given such term in Section 3.3(a).

“Construction Plan” has the meaning given such term in Section 3.2.

“Crude Oil” means crude oil produced from lease production, including lower or higher API Gravity crude oil.

“Core Units” means those production units within the Dedication Area identified as “Core Units” on the map attached hereto as Exhibit A.

“Day” means a period of twenty-four (24) consecutive hours beginning at 7:00 a.m., Central Time, on each calendar day and ending at 7:00 a.m., Central Time, on the next succeeding calendar day or such other time period that any market and/or pipeline downstream of the Gathering System uses as the definition of “Day” for its operations if such time period is inconsistent with the preceding time period.

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“Dedication Area” means all of the Interests within the areas of Gonzales, Lavaca and Fayette Counties, Texas identified on the map attached hereto as Exhibit A.

“Delivery Failure” has the meaning given such term in Section 3.5.

“Delivery Points” means the (i) outlet flange of Gatherer’s tank batteries located within the CDP where Gatherer redelivers Shipper’s Oil downstream by pipeline from the CDP, (ii) the outlet flange of Gatherer’s tank batteries located within the CDP where Gatherer redelivers Shipper’s Oil to truck loading connections at the CDP and (iii) any such other point(s) of interconnection as may be mutually agreed by Gatherer and Shipper.

“Easements” has the meaning given such term in Section 3.9.

“Effective Date” has the meaning given such term in the introductory paragraph hereto.

“Emissions” means any gaseous, liquid, solid or other substance emitted by the Gathering System, including carbon dioxide (“CO₂”), sulfur dioxide (“SO₂”), nitrogen oxides (“NO_x”), mercury (“Hg”), volatile organic compounds (“VOC”) and volatile organic material (“VOM”).

“Equivalent Volume” means a volume of Shipper’s Oil equal to (x) the volume of Shipper’s Oil received by Gatherer at the Receipt Points, minus (y) Shipper’s proportionate share of Lost Oil.

“Excess Receipt Point” has the meaning given such term in Section 3.3(b).

“Excluded Units” has the meaning given such term in Section 3.3(d).

“Excluded Volumes” has the meaning given such term in Section 9.2(b).

“Expected Production Date” has the meaning given such term in Section 3.3(a).

“Fees” means the fees payable to Gatherer hereunder as described in Section 9.2.

“FERC” has the meaning given such term in Section 12.2.

“Financing Parties” means institutions (including any trustee or agent on behalf of such institutions) providing debt financing or refinancing to Gatherer for the acquisition, development, construction, ownership, operation, maintenance or leasing of the Gathering System.

“Force Majeure” means any circumstance beyond the reasonable control of the Person experiencing such inability to perform, whether of the kind enumerated herein or not, including any such circumstances caused by the non-performance of, or breach of, the other Party of its obligations under this Agreement or acts of God, strikes, lockouts or other industrial disturbances, curtailments or shutdowns, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, power failures, storms, floods, washouts, arrests and restraints of governments and people, civil disturbances, fires, explosions, breakage or accidents to machinery or lines of pipe, modification or maintenance of machinery or lines of pipe, freezing of lines of pipe, inability to obtain at reasonable cost any land use rights such as easements, servitudes, right-of-way grants, permits, governmental approvals or licenses and inability to obtain at reasonable cost materials or supplies for constructing or maintaining facilities, actions or failures to act of Governmental Authorities, including changes in Applicable Law, and which by the exercise of due diligence such Person is unable to prevent or overcome; provided, however, that “Force Majeure” shall not include any circumstance beyond the reasonable control of such Person where the circumstance is a direct result of the willful misconduct of such Person.

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“Gatherer” has the meaning given such term in the introductory paragraph hereto.

“Gatherer Indemnitees” has the meaning given such term in Section 16.1.

“Gathering System” means, collectively, the Base Gathering System, the CDP, the Additional Segments and all associated facilities that Gatherer may construct as part thereof.

“Governmental Authority” means any government, court, tribunal, arbitrator, authority, agency, commission, official or other instrumentality of the United States or any state, county, city, tribal or other political subdivision or similar governing entity, and including any governmental, quasi-governmental or non-governmental body administering, regulating or having general oversight over oil, electricity, power or other markets.

“Initial Production Date” means the date of first production of Shipper’s Oil from a well pad connected to an additional Receipt Point described in a Construction Notice.

“Interests” means all interests that Shipper (or any of its Affiliates or any successor in interest resulting from any merger, reorganization, consolidation or as part of a sale or other disposition of all or any portion of such interests) now or hereinafter owns, controls, acquires or has the right to market (as such marketing rights may change from time to time) in Shipper’s Oil reserves of, and production from, all formations in, under or attributable to the Dedication Area, together with any pool, communitized area or unit, and all interests in any wells, whether now existing or drilled hereafter, on or completed within the Dedication Area, or within any such pool, communitized area or unit, even though such interests may be incorrectly or incompletely stated, all as the same shall be enlarged by the discharge of any burdens or by the removal of any charges or encumbrances to which any of same maybe subject as of the Effective Date, and any and all replacements, renewals and extensions or amendments of any of the same; provided, however, that “Interests” shall not include (a) any Excluded Units or Outside Units or (b) any interest of Shipper or any of its Affiliates that must be offered to a third-party working interest partner pursuant to any applicable agreement with such partner in effect on the Effective Date, and which such partner receives or elects to receive, as applicable under the affected agreement.

“LACT/ACT Unit” means a Lease Automatic Custody Transfer unit or Automatic Custody Transfer unit, in each case with Coriolis mass metering devices and electronic temperature averaging capabilities.

“Losses” means any and all judgments, losses, liabilities, amounts paid in settlement, damages, fines, penalties, deficiencies, costs and expenses (including pre- and post-judgment interest, court costs, reasonable fees of attorneys, accountants and other experts or other reasonable expenses related to any Claim).

“Lost Oil” means the volume of crude oil (expressed in Barrels) which is lost and unaccounted for in the Gathering System. Shipper’s proportionate share of Lost Oil shall be stated in Barrels and shall be determined in accordance with Gatherer’s standard allocation procedures on a proportional basis.

“Minimum Volume Commitment” has the meaning given such term in Section 9.1.

“Month” means the period commencing at 7:00 a.m., Central Time, on the first day of a calendar month and ending at 7:00 a.m., Central Time, on the first day of the next succeeding calendar month or such other time period that any market and/or pipeline downstream of the Gathering System uses as the definition of “Month” for its operations if such time period is inconsistent with the preceding time period.

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“Necessary Capacity” has the meaning given such term in Section 12.5.

“Non-Operated Interest” has the meaning given such term in Section 2.2(a).

“Outside Units” has the meaning given such term in Section 3.3(e).

“Party” and “Parties” have the meanings given such terms in the introductory paragraph hereto.

“Permissible Interruptions” has the meaning given such term in Section 5.4.

“Person” means any natural person, limited liability company, corporation, general or limited partnership, group, union, association, trust or Governmental Authority.

“PPI Adjustment” has the meaning given such term in Section 9.3.

“Preferential Fee” has the meaning given such term in Section 9.2(b).

“Prime Rate” means the per annum rate of interest announced as the “prime rate” for commercial loans posted from time to time by Wells Fargo Bank, N.A. or its successor or other bank on which the Parties agree.

“Prior Dedicated Interest” has the meaning given such term in Section 2.2(b).

“Projected Volumes” has the meaning given such term in Section 3.3(a).

“Proposed Acquired Acreage” has the meaning given such term in Section 2.8.

“Proposed Exchange Acreage” has the meaning given such term in Section 2.8.

“Proposed Released Acreage” has the meaning given such term in Section 2.9.

“Psia” means pounds per square inch absolute.

“Psig” means pounds per square inch gauge.

“Receipt Points” means the outlet flange of each of Shipper’s tank batteries located within the Dedication Area.

“Reputable and Prudent Operator” has the meaning set forth in Section 20.2.

“Reservations” has the meaning given such term in Section 6.5.

“Shipper” has the meaning given such term in the introductory paragraph hereto.

“Shipper Indemnitees” has the meaning given such term in Section 16.2.

“Shipper’s Oil” means all Interests of Shipper in Crude Oil, including, without limitation, all Crude Oil that Shipper owns, controls, acquires or has the right to market within the Dedication Area.

“Specifications” has the meaning given such term in Section 8.1.

5

“Successor” means a successor in interest resulting from any merger, reorganization, consolidation or as part of a sale or other disposition of any portion of the Interests, except as set forth in Sections 2.8, 2.9 and 2.10.

“System Completion Date” has the meaning given such term in Section 3.2.

“Tariff” means Gatherer’s TRRC Tariff and the rules and regulations of TRRC Tariff, as initially set forth on Exhibit H attached hereto, including supplements thereto and reissues thereof, under which Crude Oil is transported through the Gathering System.

“Tax” means any tax or fee imposed by any Governmental Authority.

“Term” has the meaning given such term in Article X.

“TRRC” means the Texas Railroad Commission.

ARTICLE II

DEDICATION AND COMMITMENT

2.1    Subject to Sections 2.2, 2.7, 2.8, 2.9 and 2.10, Shipper hereby dedicates and commits to Gatherer, in consideration for the gathering and delivery services to be provided by Gatherer hereunder, all of the Interests.

2.2    Shipper’s dedication and commitment of the Interests shall be subject to the Reservations as well as the following limitations:

(a)    Any Interest, other than Connection Units, which is, at any time after the Effective Date, both (a) operated by an operator other than Shipper, its Affiliate or a Successor and (b) owned less than 51% by Shipper or an Affiliate of Shipper where such ownership is measured by working interests (a “Non-Operated Interest”) shall not be subject to the dedication and commitment provided for in Section 2.1.

(b)    If Shipper acquires, after the Effective Date, any Interest which is subject to a prior dedication (a “Prior Dedicated Interest”), then such Prior Dedicated Interest shall not be subject to the dedication and commitment provided for in Section 2.1; provided, however, that, if any Prior Dedicated Interest is released from such prior dedication during the Term, then such Prior Dedicated Interest shall, effective upon such release, become subject to the dedication and commitment provided for in Section 2.1.

2.3    Commencing on the System Completion Date, Shipper shall deliver all of Shipper’s Oil produced from wells located in the Core Units to Gatherer at the Receipt Points.

2.4    Commencing on the System Completion Date, Gatherer shall provide gathering services for and accept and receive the volume of Shipper’s Oil (measured in Barrels) tendered by Shipper each Day at the Receipt Points and deliver an Equivalent Volume to the Delivery Points.

2.5    Commencing on the Initial Production Date, Shipper shall deliver all of Shipper’s Oil to Gatherer at the Receipt Point described in the applicable Construction Notice.

2.6    Commencing on the Initial Production Date, Gatherer shall provide gathering services for and accept and receive the volume of Shipper’s Oil (measured in Barrels) tendered by Shipper each Day at the Receipt Point described in the applicable Construction Notice and deliver an Equivalent Volume to the Delivery Points.

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2.7    Subject to Sections 2.8, 2.9 and 2.10, such dedication and commitment by Shipper under this Article II shall be deemed an interest that runs with the land in the Dedication Area, and the Parties agree that the dedications and commitments with regard to any Interest existing as of the Effective Date shall be deemed fully vested, and further agree that future interests in the Interests shall vest upon Shipper’s acquiring ownership, control or right to market such Interest(s). Shipper agrees to execute and deliver a memorandum in the form attached hereto as Exhibit E for Gonzales County, Exhibit F for Lavaca County and Exhibit I for Fayette County to Gatherer for recording in the real property records of each county in which any portion of the Dedication Area is located in order to evidence the dedication provision of this Article II.

2.8    If Shipper desires to sell or transfer to a third party acreage, excluding acreage within Connection Units, within the Dedication Area already dedicated under this Agreement (the “Proposed Exchange Acreage”) and receive in exchange for such acreage new acreage, not otherwise dedicated, within the Dedication Area (the “Proposed Acquired Acreage”) (such transaction, an “Acreage Swap”), Shipper shall notify Gatherer in writing of its desire for Gatherer to execute a dedication release of the Proposed Released Acreage in the Dedication Area. Shipper’s written notice will describe in reasonable detail the proposed Acreage Swap, including, as applicable: (i) a description of the portion of the Dedication Area to be released, including the number of net acres constituting the Proposed Exchange Acreage and (ii) a description of the Proposed Acquired Acreage, including the number netacres.

(a)    If the number of net acres constituting the Proposed Acquired Acreage is greater than or not less than ninety percent (90%) of the number of net acres constituting the Proposed Exchange Acreage, Gatherer shall grant such dedication release pursuant to this Section 2.8 and shall promptly deliver a recordable copy of such dedication release to Shipper.

(b)    If the number of net acres constituting the Proposed Acquired Acreage is less than ninety percent (90%) of number of net acres constituting the Proposed Exchange Acreage, Gatherer may, but shall not be required to (subject to Section 2.9), grant such dedication release pursuant to this Section 2.8.

2.9    If Shipper desires to sell or transfer to a third party acreage, excluding acreage within Connection Units, within the Dedication Area already dedicated under this Agreement other than pursuant to Section 2.8 (the “Proposed Released Acreage”), Shipper shall notify Gatherer in writing of its desire for Gatherer to execute a dedication release of the Proposed Released Acreage in the Dedication Area. Shipper’s written notice will describe in reasonable detail the portion of the Dedication Area to be released, including the number of net acres constituting the Proposed Released Acreage.

(a)    If the number of net acres constituting the Proposed Released Acreage is not more than five percent (5%) of the number of net acres included the Dedication Area at the time of such sale or transfer, Gatherer shall grant such dedication release pursuant to this Section 2.9 and shall promptly deliver a recordable copy of such dedication release to Shipper; provided, however, that Gatherer shall not be required to grant any such dedication release to the extent that the net acres included in the Dedication Area following such sell or transfer pursuant to this Section 2.9 is less than the net acres included in the Dedication Area on the Effective Date.

(b)    If the number of net acres constituting the Proposed Releases Acreage is more than five percent (5%) of number of net acres constituting the Proposed Released Acreage included the Dedication Area at the time of such sale or transfer, Gatherer may, but shall not be required to, grant such dedication release pursuant to this Section 2.9.

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2.10    If, at any time, insufficient contiguous acreage remains in the Dedication Area for Shipper to create a drilling unit, or if Shipper is otherwise unable to create a pooled unit in which it is the operator of such pooled unit, Shipper shall notify Gatherer in writing, on a unit-by-unit basis, of its desire for Gatherer to execute a dedication release of a portion of the acreage in the Dedication Area necessary to create a pooled unit with one or more third parties. Shipper’s written notice will describe in reasonable detail the proposed pooled unit, including, as applicable: (i) an explanation of why Shipper’s acreage in the Dedication Area is insufficient to create a drilling unit, (ii) a description of the portion of the Dedication Area required to be released to form such pooled unit, (iii) the identification of the third party working interest owners of such pooled unit and (iv) the size of such pooled unit. Such proposed pooled units shall not exceed seven hundred four (704)acres. Upon receipt of the information set forth in this Section 2.9, Gatherer shall grant such dedication release pursuant to this Section 2.9 and shall promptly deliver a recordable copy of such dedication release to Shipper.

ARTICLE III

CONSTRUCTION AND OWNERSHIP OF THE GATHERING SYSTEM;

CONSTRUCTION SCHEDULE

3.1    Gatherer shall, at its sole risk, cost and expense, design, acquire right-of-way for, obtain all permits from Governmental Authorities for, procure materials for, construct, equip, install, own, operate and maintain the Gathering System, all in accordance with Applicable Law and the provisions of Article IV.

3.2    By not later than October 1, 2014, Gatherer shall prepare and deliver to Shipper a detailed construction plan (a “Construction Plan”) for the completion of the Base Gathering System and the CDP and shall review the design for constructing the Base Gathering System and the CDP with Shipper. Subject to Force Majeure, Gatherer shall use commercially reasonable efforts to complete construction of the Base Gathering System and CDP so that all of the Core Units are connected to the Gathering System, and the Base Gathering System and CDP are operational, by not later than April 30, 2015 (such completion date, the “System Completion Date”). If the System Completion Date has not occurred on or before March 31, 2016, Shipper may terminate this Agreement. Within thirty (30) Days of the System Completion Date, Shipper shall commence and thereafter continue on an uninterrupted basis (except for interruptions caused by Force Majeure, Permissible Interruptions or Gatherer) delivery of Shipper’s Oil into the Base Gathering System.

3.3    Gatherer shall expand or extend, add or remove components and operate the Gathering System as necessary to connect Shipper’s wells within the Dedication Area as follows:

(a)    Shipper shall notify Gatherer of the need to install an additional Receipt Point within the Dedication Area not included as part of the Base Gathering System (a “Construction Notice”) at least 120 Days prior to the date on which the first well on the first well pad to be connected to such additional Receipt Point is expected to be spud. Each Construction Notice delivered by Shipper shall describe in reasonable detail (i) the expected date of first production of Shipper’s Oil from the first well pad to be connected to such additional Receipt Point (the “Expected Production Date”), (ii) the desired location for such additional Receipt Point, (iii) Shipper’s good faith projection of the daily volumes of Shipper’s Oil to be gathered during the initial two (2) years of production from the first well pad to be connected to such additional Receipt Point (“Projected Volumes”) and (iv)  the anticipated API Gravity of Shipper’s Oil to be produced from the first well pad to be connected to such additional Receipt Point.

(b)    Within 30 Days following the receipt of a Construction Notice, Gatherer shall notify Shipper whether it elects to install such additional Receipt Point (it being understood that Gatherer must install (and shall have no election with respect to) any additional Receipt Point within a Core Unit); provided, however, that Gatherer shall not be required to install any additional Receipt Point pursuant to this Section 3.3 in a production unit which already has a Receipt Point (subject to the following proviso) if the aggregate Receipt Points following the installation of such additional Receipt Point (an “Excess Receipt Point”) would be more than one hundred and fifty percent (150%) of the number of total number of production units then connected to the Gathering

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System; provided, further, that Gatherer shall construct, install, own and operate any Excess Receipt Point if such Excess Receipt Point does not require an additional LACT/ACT Unit and if Shipper reimburses Gatherer for the lesser of (x) $100,000 and (y) 50% of the actual costs associated with construction and installation of such Excess Receipt Point. If Gatherer elects to install any additional Receipt Point, it shall prepare and deliver to Shipper a detailed Construction Plan for the installation of the additional Receipt Point requested by such Construction Notice and the completion of the related Additional Segment and shall review with Shipper the design for constructing and/or modifying and operating such Additional Segment.

(c)    Gatherer shall use commercially reasonable efforts to complete the construction of the additional Receipt Point described in such Construction Notice and the related Additional Segment so that such Additional Segment is operational by not later than 30 Days prior to the Expected Production Date, subject to Force Majeure. Any production units connected to the Gathering System by Gatherer pursuant to this Section 3.3 shall become “Additional Units.”

(d)    Except as set forth in Section 3.3(b), if Gatherer elects not to install an additional Receipt Point or if Gatherer fails to make its election within the required 30-Day period, Shipper, its Affiliates or a third party at the direction of Shipper, shall have the right, at its sole risk, cost and expense, to install pipeline facilities and connect the wells connected or to be connected to such Additional Receipt Point. Any production units not connected to the Gathering System by Gatherer pursuant to this Section 3.3 shall be released from the Dedication Area. Any such production units connected to the Gathering System by Shipper pursuant to this Section 3.3 shall become “Excluded Units.” Shipper shall pay the Preferential Fee on Shipper’s Oil gathered from wells within an Excluded Unit.

(e)    Shipper shall have the right, at its sole risk, cost and expense, to install pipeline facilities and connect any wells outside of the Dedication Area to a point on the Gathering System. Any production units outside of the Dedication Area connected to the Gathering System by Shipper will become “Outside Units.” Shipper shall pay the Preferential Fee on Shipper’s Oil gathered from wells within an Outside Unit.

3.4    Gatherer shall design and construct the Base Gathering System, the CDP and each Additional Segment substantially as described in the applicable Construction Plan, as agreed by Gatherer and Shipper. All pipelines to be constructed pursuant to a Construction Plan (whether as part of the Base Gathering System or as part of an Additional Segment) shall be constructed of steel. Each Construction Plan shall be reasonably satisfactory to Shipper. Gatherer shall construct the Base Gathering System, the CDP and each Additional Segment with due diligence at its sole risk, cost and expense. Gatherer shall either provide a written report or schedule a conference call with Shipper regarding construction progress on a weekly basis while the Base Gathering System, the CDP and each Additional Segment are being constructed. Gatherer and Shipper shall work together to ensure completion of the Base Gathering System, the CDP and each Additional Segment in a timely manner.

3.5    Gatherer shall notify Shipper of the date on which each Additional Segment constructed or modified by Gatherer hereunder has been completed and is operational (the “Completion Date”). Except as otherwise set forth herein, by not later than 120 Days after the later of the Completion Date or the Expected Production Date, Shipper shall (a) commence and thereafter continue on an uninterrupted basis (except for interruptions caused by Force Majeure, Permissible Interruptions or Gatherer) delivery of Shipper’s Oil into such Additional Segment from the first well pad connected to the additional Receipt Point described in the applicable Construction Notice and (b) commence to pay all Fees required to be paid hereunder in connection with the gathering of such Shipper’s Oil. If Shipper does not commence such delivery within such 120-Day period, or thereafter ceases such delivery (in either case, a “Delivery Failure”), then Shipper shall, commencing on the first Day after such Delivery Failure, and continuing until Shipper has commenced or recommenced such delivery, pay all Fees that would be have been required to be paid hereunder if all of the Projected Volumes described in the applicable Construction Notice were, in fact, delivered.

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3.6    In the event that (a) the Completion Date for an Additional Segment has not occurred prior to the Initial Production Date for such Additional Segment or (b) Gatherer is unable to take all of Shipper’s Oil volumes delivered at any Receipt Point (including because of events of Force Majeure), Shipper may sell any of Shipper’s Oil produced from the wells to be connected to such Additional Segment or connected to such Receipt Point, as applicable, free from the dedications under to this Agreement until such time as the Completion Date occurs or Gatherer can resume taking all of Shipper’s Oil volumes delivered at such Receipt Point, as applicable.

3.7    In the event that Shipper makes any payment of Fees on account of a Delivery Failure pursuant to Section 3.5, all Projected Volumes used in the calculation of such payment shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment. In the event that Shipper sells Shipper’s Oil free from the dedications under to this Agreement pursuant to Section 3.6, all such volumes shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment.

3.8    Gatherer and Shipper shall collaborate to ensure that the Gathering System is configured in such a manner as to have reasonable ingress and egress to access roads and wells within the Dedication Area. With respect to any access roads constructed or to be constructed within the Dedication Area by a Party, such Party shall grant the other Party access to and use thereof. Each Party shall be responsible, and shall reimburse the other Party, for any damage caused by such Party to the other Party’s roads within the Dedication Area, ordinary wear and tear excepted.

3.9    In the event that Gatherer requires additional easements, rights-of-way, surface leases and/or easement rights under oil and gas leases (collectively, “Easements”), as applicable, in connection with the construction and/or modification of the Base Gathering System, the CDP or any Additional Segment, Gatherer shall describe such requirements in the applicable Construction Plan delivered to Shipper.

3.10    Ownership and operation of the Gathering System shall be solely vested in Gatherer, and Shipper shall have no rights to the same. Gatherer shall operate the Gathering System in accordance with the terms of the Tariff, this Agreement, Applicable Law and prevailing industry standards.

ARTICLE IV

CHARACTERISTICS OF THE GATHERING SYSTEM

4.1    Gatherer shall design, construct, equip, install, operate and maintain the Base Gathering System and any Additional Segments to have, at a minimum, the following characteristics:

(a)    the capability to reliably receive at the Receipt Points all volumes of Shipper’s Oil delivered by Shipper and re-deliver to the Delivery Points all the Equivalent Volume, in accordance with this Agreement and customary industry standards;

(b)    the capability to segregate, whether through use of separate pipelines or other means, (i) production from units generally producing 45 degree or lower API Gravity Shipper’s Oil and (ii) production from units generally producing greater than 45 degree API Gravity Shipper’s Oil, as specified in the design proposal attached hereto as Exhibit G;

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(c)    LACT/ACT Units and pipeline sample posts with capabilities sufficient to support Shipper’s royalty accounting responsibilities with respect to quantity, API Gravity, sediment and water and sulfur content for each production unit, provided, that Shipper’s use of any such data is not intended to create, nor creates, any third-party beneficiary rights; and

(d)    insulated above ground pipe, the ability to run scraper pigs and the capability to take such other actions as necessary to ensure flow reliability.

4.2    Gatherer shall design, construct, equip, install, operate and maintain the CDP to have, at a minimum, the following characteristics:

(a)    the capability to receive, store and re-deliver all of Shipper’s Oil volumes gathered from Shipper in accordance with this Agreement and customary industry standards;

(b)    facilities available to Shipper on a first priority basis for loading and unloading volumes by truck utilizing eight dual LACT/ACT Units;

(c)    at least four dedicated tanks with up to 180,000 barrels of combined tank shell storage capacity; and

(d)    the capability to blend Shipper’s volumes of Shipper’s Oil in storage tanks in order to manage Shipper’s Oil API Gravity.

4.3    Gatherer shall provide, at no additional cost to Shipper, blending services to Shipper at the CDP sufficient to blend Shipper’s Oil to between 36 degree API Gravity and 55 degree API Gravity as specified by Shipper; provided, however, that Gatherer shall perform such blending using only Shipper’s Oil and shall not use or be obligated to use Crude Oil purchased from third parties in connection with such blending services. Each Month, Shipper shall instruct Gatherer either to (a) blend Shipper’s Oil to be delivered at the Delivery Points (including trucking facilities) to a target API Gravity or (b) deliver Shipper’s Oil directly from one of Shipper’s dedicated tanks at the CDP without blending, in each case in accordance with the nomination procedures described on Exhibit B attached hereto.

4.4    Gatherer shall provide batching capability to Shipper at the CDP to maintain segregation of grades described in Section 4.1(b) out of the Delivery Points at the CDP.

4.5    Shipper shall reimburse Gatherer for the actual costs of the ongoing power requirements for operation of Gatherer’s LACT units and injection pump facilities at the Receipt Points. Gatherer shall provide, at its sole risk, cost and expense, power for the CDP.

4.6    Gatherer shall provide, at its sole risk, cost and expense, line fill and tank bottoms.

4.7    Gatherer shall not prohibit or unreasonably restrict the ability of third party pipelines to connect to the CDP. Upon the connection of a third party pipeline to the CDP, the downstream connecting pipeline(s) shall become a Delivery Point.

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ARTICLE V

QUANTITY, NOMINATION AND IMBALANCE PROCEDURES

5.1    During the Term, Shipper shall deliver and Gatherer shall take and receive 100% of Shipper’s Oil produced from wells located within the Core Units, Additional Units, the Excluded Units and the Outside Units, subject to the Reservations and the limitations described in Section 2.2.

5.2    Shipper shall provide nominations to Gatherer with respect to the quantity of Shipper’s Oil to be delivered at each Delivery Point, which nominations shall be made in accordance with the nomination procedures described on Exhibit B attached hereto.

5.3    Gatherer shall not allow any third party Crude Oil to be commingled with Shipper’s Oil on the Gathering System; provided, however, that Gatherer may receive third party Crude Oil at the CDP so long as such third party Crude Oil is and remains segregated from Shipper’s Oil and may, subject to the Rules and Regulations and after consultation with Shipper, gather third party Crude Oil.

5.4    Notwithstanding anything herein to the contrary and without liability hereunder to Shipper or any other Person (but subject to the requirements of Section 12.5), Gatherer may interrupt or reduce its receipt, gathering and delivery of Shipper’s Oil for reasons of Force Majeure, maintenance, repair, emergency, construction or other causes beyond Gatherer’s reasonable control that restrict or curtail capacity in the Gathering System or the failure or inability of the operator of the takeaway facilities at the Delivery Points to receive Crude Oil (collectively, “Permissible Interruptions”). Gatherer shall (a) provide to Shipper reasonably prompt notice of any such event, specifying the anticipated duration thereof, (b) proceed with due diligence to restore service as promptly as commercially practical under the circumstances and (c) subject to Applicable Law, take so much of Shipper’s Oil as may be physically gathered on the Gathering System given such event as a first priority and in preference to all other volumes of Crude Oil that Gatherer may otherwise receive into the Gathering System.

5.5    Shipper shall be solely responsible for any and all Crude Oil imbalances it may have with the pipelines downstream of the Gathering System and Gatherer shall have no liability whatsoever, financial or otherwise, to any Person for any such Crude Oil imbalances. Gatherer shall work in good faith in conjunction with Shipper in administering and resolving any imbalance statements that may be issued by the downstream pipelines.

5.6    The Parties shall meet by not later than two months after the Effective Date, and then at least every three months thereafter, to discuss Shipper’s Projected Volumes for the next six fiscal quarters.

ARTICLE VI

CONTROL OF OIL

6.1    Shipper, at its sole risk, cost and expense, shall own, construct, equip, install, operate and maintain, or contract for, all lines and other necessary facilities, including atmospheric tank batteries, to transport and store Shipper’s Oil as contemplated by this Agreement.

6.2    As between Gatherer and Shipper, Shipper shall be in control and possession of Shipper’s Oil and responsible for any Losses incurred by any Person in connection with Shipper’s Oil (a) until Shipper’s Oil is delivered to Gatherer at the Receipt Points and (b) after the Equivalent Volume has been redelivered by Gatherer for the account of Shipper at the Delivery Points.

6.3    As between Gatherer and Shipper, Gatherer shall be in control and possession of Shipper’s Oil and responsible for any Losses incurred by any Person in connection with Shipper’s Oil (a) after Shipper’s Oil has been delivered to Gatherer at the Receipt Points and (b) until the Equivalent Volume is redelivered for the account of Shipper at the Delivery Points.

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6.4    At all times, title to Shipper’s Oil shall remain with Shipper and not with Gatherer.

6.5    Notwithstanding anything stated to the contrary herein, Shipper reserves the following rights (the Reservations”):

(a)    The right to operate the Interests free from control by Gatherer and in such a manner as Shipper, in Shipper’s sole discretion, may deem advisable, including without limitation, the right, but never the obligation, to drill new wells, to repair and rework old wells, to renew or extend in whole or in part any leases and to abandon any well or surrender any lease in whole or in part.

(b)    The right to deliver Shipper’s Oil to the “lessors” under any leases for which such lessors are entitled to receive Shipper’s Oil in kind from the Interests under the terms of such leases.

(c)    The right to pool or unitize any leases (or any portion thereof) with other lands and leases. In the event of pooling or unitization, this Agreement shall cover Shipper’s Interest in the pool or unit and the Shipper’s Oil attributable thereto.

(d)    The right to disconnect, at Shipper’s sole risk, cost and expense, any Excluded Unit or any Outside Unit from the Gathering System.

(e)    The right to stabilize Shipper’s Oil for the purpose of lowering API Gravity, and the right to sell or transport natural gas liquids or condensate resulting from the stabilization and cooling process from the tank battery locations.

ARTICLE VII

MEASUREMENT AND TESTING

For purposes of this Agreement, (a) measurement of all volumes of Shipper’s Oil and determination of the sulfur content and API Gravity of Shipper’s Oil shall be undertaken on an “as delivered basis” and (b) determination of the API Gravity, sediment and water and sulfur content of Shipper’s Oil shall be undertaken in accordance with the procedures and requirements described on Exhibit C attached hereto. Each Day, Gatherer shall provide Shipper with all Receipt Point and Delivery Point Shipper’s Oil volumes attributable to Shipper’s Oil and tank levels in a computer file that may be uploaded by Shipper. Each Month, Gatherer shall determine the API Gravity, sediment and water and sulfur content of Shipper’s Oil received at a particular Receipt Point and provide such information to Shipper.

ARTICLE VIII

QUALITY

8.1    Shipper’s Oil shall, in the aggregate at any given Receipt Point, conform to the specifications, as may be amended or enforced from time to time, of the Tariff (collectively, the “Specifications”); provided, however, that Shipper’s Oil must be able to be blended at the CDP to meet the stricter of the following specifications: (i) the Tariff and (ii) the downstream pipelines receiving the Equivalent Volumes of Shipper’s Oil.

8.2    Should Shipper’s Oil fail at any time to conform to any and/or all of the Specifications, Gatherer may (without prior notice to Shipper) immediately suspend receipt of any off-specification Shipper’s Oil; provided, however, that Gatherer shall give notice to Shipper as promptly as is reasonably possible after Gatherer obtains knowledge of such nonconformance to allow Shipper to correct such condition(s). Should Shipper’s Oil fail to conform to any and/or all of the Specifications at a given Receipt Point, Shipper may sell such volumes of Shipper’s Oil free from the dedications under this Agreement until such time as Shipper’s Oil conforms to the Specifications. Gatherer shall not be obligated to accept Shipper’s Oil for delivery unless and until Shipper’s Oil conforms to the Specifications. Shipper shall be solely responsible for all Losses resulting from delivery of Shipper’s Oil that does not conform to the Specifications.

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8.3    The receipt by Gatherer of Shipper’s Oil that fails to meet any one of the Specifications shall not be held to be a waiver of Gatherer’s right to refuse future receipts of Shipper’s Oil or relieve Shipper of any indemnity obligation under Article XVI.

ARTICLE IX

MINIMUM VOLUME COMMITMENT; FEES

9.1    Each Month during the Term hereof, Shipper (together with its Affiliates and Successors) shall deliver to Gatherer at the Receipt Points a minimum of 15,000 Barrels per Day (the “Minimum Volume Commitment”) for ten (10) years beginning on the System Completion Date. For purpose of calculating Shipper’s delivery of the Minimum Volume Commitment, volume shall be calculated based on the trailing three (3) Month average volume gathered by Gatherer on the Gathering System. In the event that Shipper does not deliver the Minimum Volume Commitment in any given Month, Gatherer shall charge the Tier 1 Gathering Fee on the aggregate Minimum Volume Commitment for such Month in lieu of the Gathering Fees contemplated by Section 9.2(a).

9.2    As consideration of the services rendered by Gatherer under this Agreement, Shipper shall pay to Gatherer the following fees (the “Fees”):

(a)    A Gathering Fee on all of Shipper’s Oil delivered at the Delivery Points from wells in the Core Units and the Additional Units based on the following volumetric tiers:

Tier 1:	First 15,000 Barrels per Day	0	$2.00 per Barrel
Tier 2:	Greater than 15,000 and less than 30,000 Barrels per Day	0	$1.50 per Barrel
Tier 3:	Greater than 30,000 Barrels per Day	0	$1.00 per Barrel
For the avoidance of doubt, the rates in the table above are tiered. The Tier 1 rate applies to the first 15,000 Barrels per Day of transported volumes, the Tier 2 rate applies to the next 15,000 Barrels per Day of transported volumes and the Tier 3 rate applies to volumes in excess of 30,000 Barrels per Day.

(b)    A Gathering Fee on all of Shipper’s Oil delivered at the Delivery Points from wells in the Excluded Units and the Outside Units (“Excluded Volumes”) equal to $1.00 per Barrel (the “Preferential Fee”); provided, however, that in the event Shipper has delivered less than the Minimum Volume Commitment in the applicable Month, the Preferential Fee will be equal to the Tier 1 Gathering Fee with respect to such amount of Excluded Volumes as is necessary for Shipper to meet the Minimum Volume Commitment.

(c)    A Truck Loading Fee equal to $0.25 per Barrel on all of Shipper’s Oil either loaded onto or unloaded from trucks at the CDP or any other Delivery Point agreed to by the Parties.

9.3    Beginning in the second year following the System Completion Date, the Tier 2 Gathering Fee, the Tier 3 Gathering Fee, the Preferential Fee and the Truck Loading Fee will be increased by the amount equal to the annual percentage increase change in the Producer Price Index (the “PPI Adjustment”). The Tier 1 Gathering Fee will be subject to the PPI Adjustment beginning in the eleventh year following the Effective Date. In no event shall (i) the PPI Adjustment be greater than three percent (3%) in any given year or (ii) the Tier 2 Gathering Fee or the Tier 3 Gathering Fee exceed the Tier 1 Gathering Fee.

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ARTICLE X

TERM

The term of this Agreement shall commence on the Effective Date and shall terminate on the twenty-fifth (25^th) anniversary of the System Completion Date (the “Term”); provided, however, that if Gatherer has received no Shipper’s Oil from Shipper for any period of twelve (12) consecutive months, Gatherer may terminate this Agreement upon written notice to Shipper.

ARTICLE XI

STATEMENTS AND PAYMENTS

11.1    On or before the 20^th day of each Month, Gatherer shall render to Shipper a statement (in both a PDF format and an electronic format suitable for download (Excel, CVS)) showing, for the immediately preceding Month, the volume and specifications of Shipper’s Oil received at each Receipt Point and the Equivalent Volumes delivered for Shipper’s account at each Delivery Point. In such statement, Gatherer shall include a calculation of the Fees determined in accordance with Article IX. Shipper shall pay the amount shown on such statement for the Fees to Gatherer within ten (10) Days following the date of Gatherer’s statement under this Section 11.1. All amounts due hereunder and remaining unpaid when due shall bear interest at the Prime Rate plus two percent per annum until paid, except amounts disputed in good faith.

11.2    Either Party or its agent shall have the right, at reasonable times during business hours and at its sole risk, cost and expense, to examine the books and records of the other to the extent necessary to audit and verify the accuracy of any statement made pursuant to this Agreement.

11.3    In the event an error is discovered in any such statement, such error shall be adjusted without interest or penalty as soon as reasonably possible, but in any event, within two (2) months from the date that such error is discovered; provided however, that any such statement is hereby deemed final as to both Parties unless disputed in writing within two (2) years from the date of such statement.

ARTICLE XII

REGULATION

12.1    This Agreement shall be governed by and shall be construed in accordance with the laws of the State of Texas without reference to its conflict of laws principles. This Agreement and each provision hereof shall be subject to all Applicable Laws. Should either of the Parties, by force of any such Applicable Law, at any time during the Term be ordered or required to do any act inconsistent with the provisions hereof, then for that period during which the requirements of such Applicable Law are applicable to this Agreement, this Agreement shall be deemed modified to conform with the requirement of such Applicable Law, while preserving the commercial terms provided for in this Agreement to the extent reasonably possible; provided, however, that nothing herein shall alter, modify or otherwise affect the respective rights of the Parties to cancel or terminate this Agreement under the terms and conditions hereof. Further, either Party shall have the right to contest the validity of any such Applicable Law and neither acquiescence thereto nor compliance therewith for any period of time, nor any other provision contained herein, shall be construed as a waiver of such right.

12.2    Gatherer has informed Shipper, and Shipper hereby acknowledges and accepts, that the Gathering System will be an intrastate pipeline system operating only within the State of Texas, and is not intended to be subject to regulation under any Applicable Law by the Federal Energy Regulatory Commission (the “FERC”), or any successor thereof. Accordingly, as a principal condition to, and in consideration for, the execution of this Agreement by Gatherer, Shipper represents, warrants and covenants that (i) none of Shipper’s Oil delivered hereunder has been or will be dedicated to or delivered in interstate commerce, (ii) at the time Shipper’s Oil is delivered at the Receipt Points, Shipper shall not have identified any destination for Shipper’s Oil which is outside the State of Texas and Shipper does not intend to deliver any of Shipper’s Oil to be sold, transported or otherwise moved outside the State of Texas, (iii) all of Shipper’s Oil delivered to Gatherer under this Agreement shall be produced in the State of Texas, and (iv) Shipper’s Oil delivered

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hereunder is not intended to be transported or sold in interstate commerce in any manner which will subject the Gathering System to regulation by the FERC. In the event that Shipper breaches its representation, warranty and covenant contained in this Section 12.2, Gatherer, in addition to all other remedies at law or in equity, shall have the right, upon delivery of written notice to Shipper, to refuse receipt of Shipper’s Oil which has caused a breach of such representation, warranty and covenant. Gatherer’s election to refuse receipt of any of Shipper’s Oil pursuant to this Section 12.2 shall not release Shipper from any obligation to indemnify Gatherer for such breach under Article XVI or to pay for all Minimum Volume Commitments.

12.3    The Parties acknowledge that Gatherer is a common carrier for hire, and this Agreement and all gathering services performed by it on the Gathering System for Shipper pursuant to this Agreement, shall be subject to the rules and regulations in the Tariff, including, without limitation, laws and regulations that prevent discrimination in favor of any given shipper or the provision of service for consideration other than the rate set forth in a published tariff; provided, however, that as between Gatherer and Shipper, if there is a conflict between the terms and conditions of this Agreement and the terms and conditions of the Tariff, the terms and conditions of the Tariff will govern and control.

12.4    Shipper hereby covenants and agrees that it shall not, and shall not allow any Affiliate to, challenge any rate, fee, specification or other term of any tariff filed or proposed by Gatherer with any applicable Governmental Authority asserting or attempting to assert jurisdiction over all or any portion of the Gathering System so long as such rate, fee, specification or other term is no more unfavorable than the terms and conditions of this Agreement and the Tariff (it being understood that Gatherer and Shipper intend for this Agreement and the Tariff to constitute the sole terms and conditions relating to Shipper’s use of the Gathering System). This Section 12.4 shall be binding upon any Successor or any Affiliate of such Successor.

12.5    If Gatherer does not have the capacity on the Gathering System to take and receive 100% of Shipper’s Oil in accordance with Section 5.1 (the “Necessary Capacity”) (including as a result of an Event of Force Majeure), Gatherer agrees to take commercially reasonable actions to replace or restore the portion of such capacity that is unavailable. Gatherer will commence and complete such action within a commercially reasonable period of time to minimize the service disruption. During any interim period when any portion of the Necessary Capacity is unavailable, Shipper may sell any of Shipper’s Oil produced from the wells affected by the capacity shortage free from the dedications under to this Agreement until such time as Gatherer has restored the Necessary Capacity. In the event that Shipper sells Shipper’s Oil free from the dedications under to this Agreement pursuant to this Section 12.5, all such volumes shall be deemed to have been actually delivered for the purpose of satisfying the Minimum Volume Commitment.

ARTICLE XIII

TAXES AND ROYALTIES

13.1    Shipper shall be obligated to pay all Taxes levied, assessed or collected with respect to the production of Shipper’s Oil or the delivery thereof to the Receipt Points, including any Tax levied, assessed or collected as a result of any Change in Law. In addition, Shipper shall be obligated to pay all Taxes levied, assessed or collected with respect to the services rendered hereunder to the extent that any such Tax is levied, assessed or collected as a result of any Change in Law. To the extent any such Taxes are not assessed directly with respect to Shipper’s Oil or the services rendered hereunder, Gatherer shall calculate and assess any such Taxes on a pro rata basis (calculated on a per Barrel basis based on the volume of Shipper’s Oil on the Gathering System at the time such calculation is made). Notwithstanding the foregoing, any (i) Tax that may be based on the gross revenues, operating income or net income of Gatherer, or (ii) ad valorem, real property, personal property or similar Taxes based on ownership of the Gathering System, shall be borne by Gatherer.

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13.2    Shipper shall timely pay all Taxes described in Section 13.1. In the event that Shipper fails to timely pay any such Taxes, Gatherer may, upon two (2) Days’ notice, pay them and deduct the amount so paid from any sums owned by Gatherer to Shipper hereunder.

13.3    In addition to the Taxes described in Section 13.1, Shipper shall be responsible for the payment of all royalties, overriding royalties, production payments, fees, charges or other payments attributable to Shipper’s Oil (including any such royalties, overriding royalties, production payments, fees, charges or payments with respect to liquefiable hydrocarbons or other constituents contained therein or removed therefrom).

ARTICLE XIV

REPRESENTATIONS AND WARRANTIES

14.1    Each Party hereby represents and warrants to the other Party that:

(a)    Such Party is a limited partnership or limited liability company, as applicable, duly formed, validly existing and in good standing under the laws of the State of Texas (in the case of Shipper) or the State of Delaware (in the case of Gatherer), with full limited partnership or limited liability company, as applicable, power, right and authority to own and lease the assets and properties it currently owns and leases, and to carry on its business as such business is currently being conducted.

(b)    Such Party has all requisite power and authority to execute and deliver this Agreement, to perform its obligations hereunder and to consummate the transactions contemplated hereby. The execution and delivery by such Party of this Agreement and the performance by each Party of its obligations hereunder have been duly and validly authorized by all necessary limited partnership or limited liability company, as applicable, proceedings on the part of such Party. This Agreement has been duly and validly executed and delivered by such Party and constitutes the legal, valid and binding obligation of such Party enforceable against such Party in accordance with its terms, except as the same may be limited by bankruptcy, insolvency, reorganization, arrangement, moratorium or other similar laws relating to or affecting the rights of creditors generally or by general equitable principles regardless of whether considered in a proceeding at law or in equity.

(c)    The execution and delivery by such Party of this Agreement does not, and the performance by such Party of its obligations under this Agreement and the consummation of the transactions contemplated hereby will not (i) conflict with or result in a violation or breach of any of the terms, conditions or provisions of the organizational documents of such Party, (ii) violate or result in a default (or give rise to any right of termination, cancellation or acceleration) under any contract or agreement to which such Party is a party, or require any notice under any contract or agreement to which such Party is a party or by which it is bound, (iii) violate or breach any Applicable Law or (iv) require the consent, approval or authorization of, filing with or notice to any Person, which, if not obtained, would prevent such Party from performing its obligations hereunder.

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14.2    In addition to its representations and warranty in Section 12.2, Shipper represents and warrants, for itself, its successors and assigns, to Gatherer that (i) Shipper has good title to (or otherwise has the right to deliver) all of Shipper’s Oil delivered hereunder and all of Shipper’s Oil delivered hereunder is free and clear of any and all liens and encumbrances and (ii) as of the Effective Date, no Interest is a Prior Dedicated Interest.

14.3    Gatherer represents and warrants, for itself, its successors and assigns, to Shipper that from the time of receipt at the Receipt Points to the time of delivery at the Delivery Points all of Shipper’s Oil delivered hereunder shall be free and clear of any and all liens and encumbrances.

ARTICLE XV

EASEMENTS

To the extent that it may contractually or lawfully do so under its Easements, each Party hereby grants, assigns and transfers to the other Party or its designee an easement on or across the granting Party’s Easements, together with the right of ingress and egress, for the purpose of installing, using, inspecting, repairing, operating, replacing and/or removing pipe, meters, lines, electrical power-related equipment and other equipment used or useful in the performance of this Agreement. It is intended that any personal property of the Parties or their designees placed in or upon any of such real property shall remain the personal property of the respective Party or its designee, subject to removal by it within a reasonable time after the expiration or termination of this Agreement.

ARTICLE XVI

INDEMNITY

16.1    Shipper hereby agrees to indemnify, protect, defend and hold harmless Gatherer, its Affiliates and each of its and their respective officers, directors, employees, agents, partners, representatives, contractors, subcontractors, consultants and advisors (collectively, “Gatherer Indemnitees”) from and against any and all Losses arising out of or resulting from (a) Shipper’s Oil, except to the extent such Losses arise in connection with any action or failure to act by Gatherer while Shipper’s Oil is in the possession and control of Gatherer, (b) the breach of any representation or warranty of Shipper contained in this Agreement, (c) the breach of any other agreement, covenant or obligation of Shipper in this Agreement and (d) Shipper’s business operations, including all noise, odors, Emissions, pollution or other contamination whatsoever occurring in connection with such operations.

16.2    Gatherer hereby agrees to indemnify, protect, defend and hold harmless Shipper, its Affiliates and each of its and their respective officers, directors, employees, agents, partners, representatives, contractors, subcontractors, consultants and advisors (collectively, “Shipper Indemnitees”) from and against any and all Losses arising out of or resulting from (a) Shipper’s Oil if such Losses arise in connection with any action or failure to act of Gatherer while Shipper’s Oil is in the possession and control of Gatherer, (b) the breach of any representation or warranty of Gatherer contained in in this Agreement, (c) the breach of any other agreement, covenant or obligation of Gatherer in this Agreement and (d) Gatherer’s business operations, including all noise, odors, Emissions, pollution or other contamination whatsoever occurring in connection with such operations.

16.3    GATHERER HEREBY RELEASES SHIPPER FROM ANY LIABILITY FOR, AND HEREBY AGREES TO INDEMNIFY, PROTECT, DEFEND AND HOLD HARMLESS EACH SHIPPER INDEMNITEE FROM AND AGAINST, ALL LOSSES, WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF OR THE NEGLIGENCE OF ANY SHIPPER INDEMNITEE, ARISING IN CONNECTION HEREWITH IN FAVOR OF ANY EMPLOYEE, CONTRACTOR OR CONSULTANT OF ANY GATHERER INDEMNITEE ON ACCOUNT OF BODILY INJURY, DEATH OR DAMAGE TO PROPERTY OF SUCH EMPLOYEE OR CONSULTANT.

18

16.4    SHIPPER HEREBY RELEASES GATHERER FROM ANY LIABILITY FOR, AND HEREBY AGREES TO INDEMNIFY, PROTECT, DEFEND AND HOLD HARMLESS EACH GATHERER INDEMNITEE, FROM AND AGAINST, ALL LOSSES, WITHOUT REGARD TO THE CAUSE OR CAUSES THEREOF OR THE NEGLIGENCE OF ANY GATHERER INDEMNITEE, ARISING IN CONNECTION HEREWITHIN FAVOR OF ANY EMPLOYEE, CONTRACTOR OR CONSULTANT OF ANY SHIPPER INDEMNITEE ON ACCOUNT OF BODILY INJURY, DEATH OR DAMAGE TO PROPERTY OF SUCH EMPLOYEE OR CONSULTANT.

16.5    All indemnity obligations and liabilities assumed by the Parties under terms of this Agreement shall be without limit, and shall survive until the second (2^nd) anniversary of the termination of this Agreement.

16.6    Each Party shall procure and maintain during the entire Term, at its own expense, with an insurance company or companies authorized to do business in the State of Texas or through a self-insurance program, insurance coverages of the kind and in the specified minimum amounts set forth on Exhibit D attached hereto.

ARTICLE XVII

NOTICES AND STATEMENTS

17.1    All notices, statements, payments and other communications required or permitted to be given hereunder shall be in writing and shall be deemed to have been effectively given when deposited in the United States mail or with an overnight courier service, or when sent via email or facsimile, as the case may be, addressed to:

Notices:

If to Gatherer:	If to Shipper:
Republic Midstream, LLC c/o ArcLight Capital Partners, LLC 200 Clarendon Street, 55th Floor Boston, MA 02117 Attn: Christine Miller Email: cmiller@arclightcapital.com Facsimile: (617) 867-4698	Penn Virginia Oil & Gas, L.P. 840 Gessner, Suite 800 Houston, TX 77024 Attn: Vice President, Oil & Gas Marketing Email: jill.zivley@pennvirginia.com Facsimile: (713) 722-6601

19

With a copy to:	With a copy to:
American Midstream Partners, L.P. 1400 16th Street, Suite 310 Denver, CO 80202 Attn: William B. Mathews Email: bmathews@americanmidstream.com Facsimile: (720) 457-6040 and JP Energy Partners LP 600 East Las Colinas Blvd., Suite 2000 Irving, TX 75039 Attn: Legal Department Email: Legal@jpep.com Facsimile: (972) 444-0320	Penn Virginia Corporation Four Radnor Corporate Center, Suite 200 100 Matsonford Road Radnor, PA 19087-4564 Attn: General Counsel Email: nancy.snyder@pennvirginia.com Facsimile: (610) 687-3688

Statements:

Penn Virginia Oil & Gas, L.P.

840 Gessner, Suite 800

Houston, TX 77024

Attn: Vice President, Oil & Gas Marketing

Email: jill.zivley@pennvirginia.com

Facsimile: (713) 722-6601

Payments:

Comerica Bank

1717 Main Street

Dallas, Texas 75201

ABA Routing #111000753

For Account of: Republic Midstream, LLC

Account #: 1881761173

17.2    Notices of change of address of either Party shall be given in writing to the other in the manner aforesaid and shall be observed in the giving of all future notices, statements or other communications required or permitted to be given hereunder.

ARTICLE XVIII

FORCE MAJEURE

18.1    Upon occurrence of an event of Force Majeure, Shipper’s or Gatherer’s obligation to perform, wholly or in part, any commitment or undertaking set forth in this Agreement, other than the obligation to make payments of amounts due hereunder (including the obligations set forth in Section 9.1), shall be suspended to the extent and for the period of such Force Majeure condition; provided, however, that the Party whose obligations are so affected shall promptly give written notice to the other Party describing the event of Force Majeure in reasonable detail.

20

18.2    Should there be an event of Force Majeure affecting performance hereunder, such events shall be remedied with all reasonable dispatch to ensure resumption of normal performance.

18.3    Notwithstanding Section 18.2, settlement of strikes and lockouts shall be entirely within the discretion of the Party affected, and the requirement in Section 18.2 that any event of Force Majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes and lockouts by acceding to the demands of the third parties directly or indirectly involved in such strikes or lockouts when such course is inadvisable in the discretion of the Party having such difficulty.

ARTICLE XIX

CONFIDENTIAL INFORMATION

19.1    Except as permitted by Section 19.2, (i) each Party shall keep confidential all Confidential Information and shall not disclose any Confidential Information to any Person and (ii) each Party shall use the Confidential Information only in connection with the operation of the Gathering System.

19.2    Notwithstanding Section 19.1, but subject to the other provisions of this Article XIX, a Party may make the following disclosures and uses of Confidential Information:

(a)    disclosures required for such Party to perform its duties under this Agreement;

(b)    disclosures to an Affiliate of such Party, including the representatives of such Affiliate, for purposes in furtherance of the operation of the Gathering System and has agreed to abide by the terms of this Article XIX;

(c)    disclosures to a Person that is not a Party or an Affiliate of a Party, if such Person has been retained by Gatherer to provide services in connection with the operation of the Gathering System and has agreed to abide by the terms of this Article XIX;

(d)    disclosures to a bona-fide potential direct or indirect purchaser of the Gathering System and the advisors or representatives of such potential purchaser, if such potential purchaser has agreed to abide by the terms of this Article XIX;

(e)    disclosures to working interest or joint venture partners with respect to leases or wells in the Dedication Area;

(f)    disclosures required by Applicable Law or the rules of any national securities exchange or automated quotation system;

(g)    disclosures to financial institutions requiring such disclosure as a condition precedent to making or renewing a loan or in connection with any covenant made in connection with such loan(s) or any existing loan of such Party or its Affiliates; and

(h)    disclosures to the legal advisors, financial advisors, consultants or independent certified public accountants for such Party or its Affiliates.

19.3    Each Party shall take such precautionary measures as may be required to ensure (and such Party shall be responsible for) compliance with this Article XIX by any of its representatives and other Persons to which it may disclose Confidential Information in accordance with this Article XIX.

19.4    The Parties agree that no adequate remedy at law exists for a breach or threatened breach of any of the provisions of this Article XIX, the continuation of which, if not remedied, shall cause the non-breaching Party to suffer irreparable harm. Accordingly, the Parties agree that each Party shall be entitled, in addition to other remedies that may be available

21

to such Party, to immediate injunctive relief from any breach of any of the provisions of this Article XIX and to specific performance of its rights hereunder, as well as to any other remedies available at law or in equity.

19.5    The obligations of the Parties under this Article XIX shall terminate on the second anniversary of the termination of this Agreement.

ARTICLE XX

ASSIGNMENT OR SALE OF GATHERING SYSTEM

20.1    Gatherer may not sell, assign or transfer any of its rights or obligations under this Agreement, or any of its right, title and interests in or to the Gathering System, without the prior written consent of Shipper which shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, Gatherer may, without Shipper’s consent, (i) sell all, or any portion of, the Gathering System to JP Energy Partners, LP, American Midstream Partners L.P. or any respective subsidiary thereof, (ii) assign, mortgage, hypothecate, pledge or otherwise encumber all or any portion of Gatherer’s interest in and to this Agreement (including its rights and obligations hereunder), and/or its right, title and interest in and to the Gathering System in favor of any Financing Party and its successors and assigns (each a, “Collateral Assignment”), and (iii) following the System Completion Date, sell, assign or transfer all, but not less than all, of the Gathering System, and the associated rights and obligations under this Agreement, to a Reputable and Prudent Operator.

20.2    As used herein, a “Reputable and Prudent Operator” shall mean any entity that: (i) is a pipeline operator which, in Shipper’s reasonable opinion, is experienced in operating gathering and pipelines systems similar to the Gathering System; (ii) has not filed a voluntary bankruptcy proceeding or been declared a bankrupt involuntarily; (iii) has not been blocked by any Governmental Authority from holding any permits, licenses or approvals necessary to operate the Gathering System as contemplated by this Agreement; (iv) has a health, safety and environmental compliance record reasonably satisfactory to Shipper; and (v) has a net worth of $100 million or more on a consolidated basis.

20.3    Notwithstanding the foregoing or anything in this Agreement to the contrary, Shipper agrees that in connection with a Collateral Assignment, any such Financing Party may assign such right, title and interests in and to this Agreement and/or the Gathering System to a Reputable and Prudent Operator in connection with the sale, transfer or exchange of its rights under this Agreement or right, title, and interests in the Gathering System or for the purpose of operating the Gathering System pursuant to such assignment upon and after the exercise of its rights and enforcement of its remedies against the Gathering System under any deed of trust or other security instrument creating a lien, security interest or other rights in its favor.

20.4    No assignment of this Agreement shall be made by Shipper except to a Person that is acquiring an interest in all or part of the Dedicated Area contemporaneous with such assignment. Furthermore, Shipper may not sell, assign or transfer any of its rights or obligations under this Agreement without the prior written consent of Gatherer, which shall not be unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing, Shipper may, without Gatherer’s consent, sell, assign or transfer any of its rights or obligations under this Agreement to a creditworthy entity with net assets at least equal to the net assets of Shipper on the date of assignment or transfer.

ARTICLE XXI

MISCELLANEOUS

21.1    All Article, Section and Exhibit references used in this Agreement are to Articles, Sections and Exhibits to this Agreement unless otherwise specified. The Exhibits attached to this Agreement constitute a part of this Agreement and are incorporated herein for all purposes.

22

21.2    If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb). Unless the context of this Agreement clearly requires otherwise, words importing the masculine gender shall include the feminine and neutral genders and vice versa. The words “includes” or “including” shall mean “includes without limitation” or “including without limitation,” the words “hereof,” “hereby,” “herein,” “hereunder” and similar terms in this Agreement shall refer to this Agreement as a whole and not any particular Section or Article in which such words appear and any reference to an Applicable Law shall include any amendment thereof or any successor thereto and any rules and regulations promulgated thereunder. Currency amounts referenced herein are in U.S. Dollars.

21.3    This Agreement may be executed in as many counterparts as deemed necessary. When so executed, the aggregate counterparts shall constitute one Agreement and shall have the same effect as if both Parties signing counterparts had executed the same instrument.

21.4    This Agreement may not be amended or modified except pursuant to a written instrument signed by both of the Parties. Either Party may waive on its own behalf compliance by the other Party with any term or provision hereof; provided, however, that any such waiver shall be in writing and shall not bind the non-waiving Party. The waiver by either Party of a breach of any term or provision shall not be construed as a waiver of any subsequent breach of the same or any other provision.

21.5    This Agreement is binding upon and shall inure to the benefit of the successors and permitted assigns of the Parties.

21.6    The Parties agree and confirm that this Agreement was prepared jointly by both Parties and not by any one Party to the exclusion of the other.

21.7    Except as provided in Article XVI, this Agreement is not intended to confer upon any Person not a party hereto any rights or remedies hereunder, and no Person other than the Parties is entitled to rely on or enforce any provision hereof.

21.8    This Agreement (including the Exhibits attached hereto) contains the entire agreement between the Parties with respect to the subject matter hereof, and there are no prior agreements, understandings, representations or warranties between the Parties, other than those set forth or referred to herein or therein.

21.9    NO PARTY, INCLUDING AND ON BEHALF OF, GATHERER INDEMNITIES AND SHIPPER INDEMNITIES, SHALL UNDER ANY CIRCUMSTANCES BE LIABLE FOR SPECIAL, CONSEQUENTIAL, INCIDENTAL, PUNITIVE OR EXEMPLARY DAMAGES, WHETHER BY STATUTE, IN TORT OR BY CONTRACT OR OTHERWISE, EXCEPT WHERE SUCH DAMAGES WERE CAUSED BY THE WILLFUL MISCONDUCT OR FRAUD OF SUCH PARTY. THE PROVISIONS OF THIS SECTION 21.9 SHALL BE ENFORCEABLE ONLY TO THE EXTENT ALLOWED BY, AND SHALL BE SUBJECT TO, ANY APPLICABLE REQUIREMENTS AND PROCEDURES SET FORTH IN, APPLICABLE LAW.

21.10    In the event of litigation arising with respect to this Agreement, either Party may offer into evidence an electronic image of the signed Agreement, any amendment hereto or any correspondence exchanged in connection herewith and shall not be required to maintain or produce an original paper copy of any such document. Any such electronic copy shall be deemed an original and may be admitted into evidence for all purposes, notwithstanding the “best evidence” rule or any other rule of evidence that would prohibit or restrict its admissibility.

[Signature Page Follows]

23

IN WITNESS WHEREOF, the Parties have executed this Agreement as of the day and year hereinabove first written.

REPUBLIC MIDSTREAM, LLC

By:/s/ Daniel R. Revers

Name:    Daniel R. Revers

Title:    President

PENN VIRGINIA OIL & GAS, L.P.

By:Penn Virginia Oil & Gas GP LLC,

its general partner

By:/s/ H. Baird Whitehead

Name:    H. Baird Whitehead

Title:    President and Chief Executive Officer

24

EXHIBIT A

DEDICATION AREA

See attached map

A-1

EXHIBIT B

NOMINATION PROCEDURES

Shipper will submit monthly nomination quantities stated in Barrels for each Month not later than the 15th Day of the prior Month. All nominations shall be made to Gatherer’s electronic bulletin board, unless otherwise mutually agreed. Nominations must designate the Receipt Points and Delivery Points to be used, the estimated monthly quantities to be received at each Receipt Point and delivered at each Delivery Point (including for the truck loading Delivery Point inside the CDP) and the estimated API Gravity and sulfur content for such volumes. All nominations must state the expected market for such quantities.

Once nominated by Shipper for the Month, Shipper may change the nomination quantity at any Receipt Point or Delivery Point by submitting a revised nomination quantity no later than 11:30 a.m., Central Time, on the business day prior to the Day such revised quantity is to be effective.

B-1

EXHIBIT C

MEASUREMENT AND TESTING

1. Crude oil shall be measured by LACT/ACT Units installed, maintained and operated by Gatherer or its designee and computations made in accordance with accepted API and industry practices. Such LACT/ACT Units shall be operated within appropriate flow rate, temperature and pressure ranges for existing operating conditions. Volume computations shall be made as accurately as possible and within the accuracy prescribed by the manufacturer of the recording and computing equipment used utilizing accepted API and industry practices and procedures.

2. The unit of volume for purposes of measurement shall be one (1) 42 U.S. gallon barrel of Crude Oil at a temperature base of sixty degrees Fahrenheit (60F) containing no suspended sediment and water and at a pressure base of fourteen and sixty-five hundredths (14.65) psia (0 psig).

3. Temperature shall be determined by a dynamic electronic temperature averaging device. The API Gravity, sulfur content and suspended sediment and water content of the Crude Oil shall be determined by measurement of the oil samples collected from the LACT/ACT Units and pipeline sample pots. Analysis of the accumulated samples shall be made at operational times agreed upon by both the Shipper and the Gatherer no less than once per Month.

4. Shipper may access electronic readings remotely and may download electronic readings to its SCADA system.

5. The accuracy of Gatherer’s measuring equipment shall be verified by Gatherer or its designee every three (3) Months. Upon request by Shipper, notice of the date and time of the testing of such equipment or for the quality of the Crude Oil shall be given by Gatherer to Shipper sufficiently in advance to permit convenient arrangement for Shipper’s representative to be present. If after proper notice, Shipper fails to have a representative present, the results of the test shall nevertheless be considered accurate. All tests shall be made at Gatherer’s expense, except that Shipper shall bear the expense of tests made at its request if the meter factor is determined to deviate, plus or minus, five one-hundredths of one percent (0.05%) or less from the meter factor previously determined.

6. If at any time the measuring or testing equipment is found to be out of service or registering inaccurately in any percentage, it shall be adjusted at once to read accurately within the limits prescribed by the manufacturer. If such conditions exist, then corrections shall be made for any period which is definitely known or agreed upon. The quantity of Crude Oil delivered during that period shall be determined by the first of the following methods which is available:

i) by correcting the error if the percentage of the error is ascertainable by calibration, test or mathematical calculation; or

ii) by estimating the quantity or quality delivered based on deliveries under similar conditions during a period when the equipment was registering accurately only if no other data exists.

7. Gatherer and Shipper shall have the right to inspect equipment installed or furnished by the other and the charts and other measurement or testing data of the other at all times during regular business hours but the reading, calibration and adjustment of such equipment shall be done only by the Party with the responsibility for operating such equipment. Gatherer shall preserve all test data, charts and other similar records for a period of at least two (2) years.

C-1

EXHIBIT D

REQUIRED INSURANCE

See attached

D-1

EXHIBIT E

FORM OF MEMORANDUM OF DEDICATION

NOTICE OF CONFIDENTIALITY RIGHTS: IF YOU ARE A NATURAL PERSON, YOU MAY REMOVE OR STRIKE ANY OR ALL OF THE FOLLOWING INFORMATION FROM ANY INSTRUMENT THAT TRANSFERS AN INTEREST IN REAL PROPERTY BEFORE IT IS FILED FOR RECORD IN THE PUBLIC RECORDS: YOUR SOCIAL SECURITY NUMBER OR YOUR DRIVER’S LICENSE NUMBER.

After recordation, return to: Republic Midstream, LLC c/o ArcLight Capital Partners, LLC 200 Clarendon Street, 55^th Floor Boston, MA 02117 Attn.: Land Department Reserved For Recording Information

MEMORANDUM OF DEDICATION

STATE OF TEXAS§

§KNOW ALL MEN BY THESE PRESENTS THAT:

COUNTY OF GONZALES§

For good and valuable consideration, Penn Virginia Oil & Gas, L.P., a Texas limited partnership (“Shipper”), with offices at 840 Gessner, Suite 800, Houston, TX 77024, has entered into that certain CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of July 30, 2014 (the “Gathering Agreement”) with Republic Midstream, LLC, a Delaware limited liability company (“Gatherer”), with offices at 200 Clarendon Street, 55^th Floor, Boston, MA 02117, whereby, Shipper has committed and dedicated to Gatherer, and Gatherer has agreed to receive, all of Shipper’s Oil owned or controlled by Shipper in the Dedication Area (as defined therein and as further described on Exhibit A attached hereto) for a term of twenty (20) years, as further described in, and as pursuant to the terms of, such Gathering Agreement.

This Memorandum is placed on record for the purpose of giving notice of the Gathering Agreement. In the event the Gathering Agreement terminates or acreage is released from dedication, in accordance with its terms, Gatherer shall promptly provide to Shipper an executed memorandum of release in recordable form evidencing that such dedication (or portion thereof) is no longer in force or effect.

[Signature Pages Follow]

E-1

IN WITNESS WHEREOF, Shipper and Gatherer have executed this Memorandum as of the date set forth below to be effective for all purposes as provided herein.

SHIPPER:

PENN VIRGINIA OIL & GAS, L.P.

By:Penn Virginia Oil & Gas GP LLC,

its general partner

By:/s/ Edward L. Johnson

Name:Edward L. Johnson

Title:Vice President, Land

STATE OF TEXAS    §

§

COUNTY OF HARRIS    §

This instrument was acknowledged before me on July 30th, 2014 by Edward L. Johnson, Vice President of Penn Virginia Oil & Gas GP LLC, a Delaware limited liability company, on behalf of said company.

/s/ Jan L. Farrell

Jan L. Farrell

Notary Public in and for

The State of Texas

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:/s/ Daniel R. Revers

Name:    Daniel R. Revers

Title:    President

COMMONWEALTH OF MASSACHUSETTS§

§

COUNTY OF SUFFOLK§

This instrument was acknowledged before me on July 29th, 2014 by Daniel R. Revers, President of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

/s/ Elisabeth A. Wallace

Elisabeth A. Wallace

Notary Public in and for

The State of Massachusetts

E-2

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

E-3

EXHIBIT F

FORM OF MEMORANDUM OF DEDICATION

NOTICE OF CONFIDENTIALITY RIGHTS: IF YOU ARE A NATURAL PERSON, YOU MAY REMOVE OR STRIKE ANY OR ALL OF THE FOLLOWING INFORMATION FROM ANY INSTRUMENT THAT TRANSFERS AN INTEREST IN REAL PROPERTY BEFORE IT IS FILED FOR RECORD IN THE PUBLIC RECORDS: YOUR SOCIAL SECURITY NUMBER OR YOUR DRIVER’S LICENSE NUMBER.

After recordation, return to: Republic Midstream, LLC c/o ArcLight Capital Partners, LLC 200 Clarendon Street, 55^th Floor Boston, MA 02117 Attn.: Land Department Reserved For Recording Information

MEMORANDUM OF DEDICATION

STATE OF TEXAS§

§KNOW ALL MEN BY THESE PRESENTS THAT:

COUNTY OF LAVACA§

For good and valuable consideration, Penn Virginia Oil & Gas, L.P., a Texas limited partnership (“Shipper”), with offices at 840 Gessner, Suite 800, Houston, TX 77024, has entered into that certain CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of July 30, 2014 (the “Gathering Agreement”) with Republic Midstream, LLC, a Delaware limited liability company (“Gatherer”), with offices at 200 Clarendon Street, 55^th Floor, Boston, MA 02117, whereby, Shipper has committed and dedicated to Gatherer, and Gatherer has agreed to receive, all of Shipper’s Oil owned or controlled by Shipper in the Dedication Area (as defined therein and as further described on Exhibit A attached hereto) for a term of twenty (20) years, as further described in, and as pursuant to the terms of, such Gathering Agreement.

This Memorandum is placed on record for the purpose of giving notice of the Gathering Agreement. In the event the Gathering Agreement terminates or acreage is released from dedication, in accordance with its terms, Gatherer shall promptly provide to Shipper an executed memorandum of release in recordable form evidencing that such dedication (or portion thereof) is no longer in force or effect.

[Signature Pages Follow]

F-1

IN WITNESS WHEREOF, Shipper and Gatherer have executed this Memorandum as of the date set forth below to be effective for all purposes as provided herein.

SHIPPER:

PENN VIRGINIA OIL & GAS, L.P.

By:Penn Virginia Oil & Gas GP LLC,

its general partner

By:/s/ Edward L. Johnson

Name:Edward L. Johnson

Title:Vice President, Land

STATE OF TEXAS    §

§

COUNTY OF HARRIS    §

This instrument was acknowledged before me on July 30th, 2014 by Edward L. Johnson, Vice President of Penn Virginia Oil & Gas GP LLC, a Delaware limited liability company, on behalf of said company.

/s/ Jan L. Farrell

Jan L. Farrell

Notary Public in and for

The State of Texas

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:/s/ Daniel R. Revers

Name:    Daniel R. Revers

Title:    President

COMMONWEALTH OF MASSACHUSETTS§

§

COUNTY OF SUFFOLK§

This instrument was acknowledged before me on July 29th, 2014 by Daniel R. Revers, President of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

/s/ Elisabeth A. Wallace

Elisabeth A. Wallace

Notary Public in and for

The State of Massachusetts

F-2

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

F-3

EXHIBIT G

DESIGN PROPOSAL

See attached

G-1

EXHIBIT H

TARIFF

See attached

H-1

EXHIBIT I

FORM OF MEMORANDUM OF DEDICATION

NOTICE OF CONFIDENTIALITY RIGHTS: IF YOU ARE A NATURAL PERSON, YOU MAY REMOVE OR STRIKE ANY OR ALL OF THE FOLLOWING INFORMATION FROM ANY INSTRUMENT THAT TRANSFERS AN INTEREST IN REAL PROPERTY BEFORE IT IS FILED FOR RECORD IN THE PUBLIC RECORDS: YOUR SOCIAL SECURITY NUMBER OR YOUR DRIVER’S LICENSE NUMBER.

After recordation, return to: Republic Midstream, LLC c/o ArcLight Capital Partners, LLC 200 Clarendon Street, 55^th Floor Boston, MA 02117 Attn.: Land Department Reserved For Recording Information

MEMORANDUM OF DEDICATION

STATE OF TEXAS§

§KNOW ALL MEN BY THESE PRESENTS THAT:

COUNTY OF FAYETTE§

For good and valuable consideration, Penn Virginia Oil & Gas, L.P., a Texas limited partnership (“Shipper”), with offices at 840 Gessner, Suite 800, Houston, TX 77024, has entered into that certain CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of July 30, 2014 (the “Gathering Agreement”) with Republic Midstream, LLC, a Delaware limited liability company (“Gatherer”), with offices at 200 Clarendon Street, 55^th Floor, Boston, MA 02117, whereby, Shipper has committed and dedicated to Gatherer, and Gatherer has agreed to receive, all of Shipper’s Oil owned or controlled by Shipper in the Dedication Area (as defined therein and as further described on Exhibit A attached hereto) for a term of twenty (20) years, as further described in, and as pursuant to the terms of, such Gathering Agreement.

This Memorandum is placed on record for the purpose of giving notice of the Gathering Agreement. In the event the Gathering Agreement terminates or acreage is released from dedication, in accordance with its terms, Gatherer shall promptly provide to Shipper an executed memorandum of release in recordable form evidencing that such dedication (or portion thereof) is no longer in force or effect.

[Signature Pages Follow]

I-1

IN WITNESS WHEREOF, Shipper and Gatherer have executed this Memorandum as of the date set forth below to be effective for all purposes as provided herein.

SHIPPER:

PENN VIRGINIA OIL & GAS, L.P.

By:Penn Virginia Oil & Gas GP LLC,

its general partner

By:/s/ Edward L. Johnson

Name:Edward L. Johnson

Title:Vice President, Land

STATE OF TEXAS    §

§

COUNTY OF HARRIS    §

This instrument was acknowledged before me on July 30th, 2014 by Edward L. Johnson, Vice President of Penn Virginia Oil & Gas GP LLC, a Delaware limited liability company, on behalf of said company.

/s/ Jan L. Farrell

Jan L. Farrell

Notary Public in and for

The State of Texas

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:/s/ Daniel R. Revers

Name:    Daniel R. Revers

Title:    President

COMMONWEALTH OF MASSACHUSETTS§

§

COUNTY OF SUFFOLK§

This instrument was acknowledged before me on July 29th, 2014 by Daniel R. Revers, President of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

/s/ Elisabeth A. Wallace

Elisabeth A. Wallace

Notary Public in and for

The State of Massachusetts

I-2

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

I-3

EX-12.1

Exhibit 12.1

Penn Virginia Corporation and Subsidiaries

Statement of Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends

(in thousands, except ratios)

	Nine Months Ended
	September 30,			Year Ended December 31,
	2014			2013			2012			2011			2010			2009
Earnings:
Income (loss) from continuing operations before income taxes	$	7,763		$	(220,766	)	$	(173,291	)	$	(221,070	)	$	(108,178	)	$	(216,750	)
Fixed charges	85,783			97,903			66,616			62,002			60,003			52,539
Capitalized interest	(4,875		)	(5,266		)	(803		)	(1,983		)	(1,384		)	(2,318		)
Preferred stock dividend requirements	(11,150		)	(10,647		)	(2,793		)	—			—			—
	$	77,521		$	(138,776	)	$	(110,271	)	$	(161,051	)	$	(49,559	)	$	(166,529	)
Fixed charges:
Interest expense	$	67,716		$	78,841		$	59,339		$	56,216		$	53,679		$	44,231
Capitalized interest	4,875			5,266			803			1,983			1,384			2,318
Rent factor	2,042			3,149			3,681			3,803			4,940			5,990
Preferred stock dividend requirements	11,150			10,647			2,793			—			—			—
	$	85,783		$	97,903		$	66,616		$	62,002		$	60,003		$	52,539
Ratio of earnings to fixed charges and preferred stock dividends 1	—			—			—			—			—			—

¹ During the nine months ended September 30, 2014, earnings were deficient by $8,262. During the years ended December 31, 2013, 2012, 2011, 2010 and 2009, earnings were deficient by $236,679, $176,887, $223,053, $109,562 and $219,068, respectively, regarding the coverage of fixed charges and preferred stock dividends.

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, H. Baird Whitehead, President and Chief Executive Officer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: October 29, 2014

/s/ H. BAIRD WHITEHEAD

H. Baird Whitehead

President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Steven A. Hartman, Senior Vice President and Chief Financial Officer of Penn Virginia Corporation (the “Registrant”), certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of the Registrant (this “Report”);

2. Based on my knowledge, this Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other financial information included in this Report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this Report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the Registrant and we have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the Registrant’s disclosure controls and procedures and presented in this Report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) Disclosed in this Report any change in the Registrant’s internal control over financial reporting that occurred during the Registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the Registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the Registrant’s auditors and the audit committee of the Registrant’s board of directors:

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Date: October 29, 2014

/s/ STEVEN A. HARTMAN

Steven A. Hartman

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the three months ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, H. Baird Whitehead, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 29, 2014

/s/ H. BAIRD WHITEHEAD

H. Baird Whitehead

President and Chief Executive Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Penn Virginia Corporation (the “Company”) on Form 10-Q for the three months ended September 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Steven A. Hartman, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 29, 2014

/s/ STEVEN A. HARTMAN

Steven A. Hartman

Senior Vice President and Chief Financial Officer

This written statement is being furnished to the Securities and Exchange Commission as an exhibit to the Report. A signed original of this written statement required by Section 906 has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Acquisitions and Divestitures - Additional Information (Detail) (USD $)	3 Months Ended	9 Months Ended		12 Months Ended	15 Months Ended	3 Months Ended		3 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Jul. 31, 2014	Sep. 30, 2014 Eagle Ford Shale, Lavaca County acre	Jul. 31, 2014 Eagle Ford Shale, Lavaca County	Sep. 30, 2014 South Texas Oil Gathering Sys. Development Rights	Sep. 30, 2014 Selma Chalk	Jun. 30, 2014 Selma Chalk	Mar. 31, 2014 South Texas Natural Gas Gathering Assets
Business Acquisition [Line Items]
Payments To Settle Obligations Assumed In Acquisition Net		$ (33,712,000)	$ 43,023,000	$ (22,500,000)
Purchased Oil and Gas Interests, Gross Area Of Property Acquired (in acres)						13,125
Proceeds from Sale of Intangible Assets								147,100,000
Impairment of Oil and Gas Properties	6,100,000									117,900,000
Business Combination, Disputed Contractual Adjustments, Settled in Arbitration	35,100,000
Proceeds from Sale of Oil and Gas Property and Equipment									67,900,000		96,000,000
Gain (Loss) on Sale of Oil and Gas Property								147,100,000			67,300,000
Sale Leaseback Transaction, Recognized Gain, Net								63,000,000			56,700,000
Sale Leaseback Transaction, Deferred Gain, Gross								84,100,000			10,600,000
Sale Leaseback Transaction, Current Period Gain Recognized	100,000	300,000
Sale Leaseback Transaction, Deferred Gain, Current	400,000	400,000
Sale Leaseback Transaction, Deferred Gain, Net	9,900,000	9,900,000
Purchased Oil and Gas Interests, Net Area Of Property Acquired (in acres)						11,660
Asset Acquisition, Purchase Price							45,600,000
Business Combination, Consideration Transferred						34,900,000
Business Combination, Consideration Transferred, Liabilities Incurred						10,700,000
Arbitration Settlement Interest					$ 1,300,000

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Shareholders' Equity Rollforward (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended					9 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Apr. 24, 2013	Sep. 30, 2014 Preferred stock		Sep. 30, 2013 Preferred stock	Dec. 31, 2012 Preferred stock	Sep. 30, 2014 Common stock		Sep. 30, 2013 Common stock		Sep. 30, 2014 Paid-in capital		Sep. 30, 2013 Paid-in capital		Sep. 30, 2014 Accumulated deficit		Sep. 30, 2013 Accumulated deficit		Sep. 30, 2014 Deferred compensation obligation		Sep. 30, 2013 Deferred compensation obligation		Sep. 30, 2014 Accumulated other comprehensive income		Sep. 30, 2013 Accumulated other comprehensive income		Sep. 30, 2014 Treasury stock		Sep. 30, 2013 Treasury stock		Sep. 30, 2014 Depositary Shares	Sep. 30, 2014 Convertible Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Stock Issued during period, Fair Value per Share, Acquisitions									$ 4.23
Preferred Stock, Value, Issued					$ (313,330)	[1]				$ 3,250								$ 310,080
Share-based Compensation					2,638		4,781
Conversion of Stock, Shares Converted																																						355,482	3,555
Stock Issued During Period, Shares, Conversion of Convertible Securities					5,924,706
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance					788,804		895,116			1,150	[2]	1,150	1,150	466	[2]	364		891,351	[2]	849,046		(104,180)		45,790		2,792		3,111		267	[3]	(982)	[3]	(3,042)		(3,363)
Net income (loss)	89,661		(98,900)		8,102		(140,721)															8,102
Dividends Declared					(11,081)	[1]
Dividends Declared							(5,175)	[2]																(5,175)	[2]
All Other Changes					(488)	[4]	46,563	[4]		(356)	[2],[4]			62	[2],[4]	101	[4],[5]	3,871	[2],[4]	46,404	[4],[5]					314	[4]	(384)	[4]	74	[3],[4]	56	[3],[4]	(197)	[4]	386	[4]
As of ending balance	1,098,667		795,783		1,098,667		795,783			4,044	[2]	1,150	1,150	528	[2]	465		1,205,302	[2]	895,450		(111,415)		(100,106)		3,106		2,727		341	[3]	(926)	[3]	(3,239)		(2,977)
Preferred stock dividends	(7,641)	[6]	(1,725)	[6]	(11,081)	[6]	(5,175)	[6]														(11,081)	[1]
Preferred Stock Conversions, Inducements	$ (888)		$ 0		$ (4,256)		$ 0

[1] Includes dividends of $450.00 per share on our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) and $198.33 per share on our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”).

[2] A total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5,924,706 shares of our common stock during the nine months ended September 30, 2014. We made payments of $4.3 million to induce the conversion of 3,527 of these shares.

[3] The Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the nine months ended September 30, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $114 and $86 and are presented above net of taxes of $40 and $30.

[4] Includes equity-classified share-based compensation of $2,638 and $4,781 for the nine months ended September 30, 2014 and 2013.

[5] Includes the Shares, with a fair value of $4.23 per share, that were issued to MHR in connection with the EF Acquisition.

[6] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

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Long-Term Debt - Additional Information (Detail) (USD $)	3 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 Revolving credit facility	Oct. 28, 2013 Revolving credit facility	Sep. 30, 2014 Revolving credit facility Minimum	Sep. 30, 2014 Revolving credit facility Maximum	Sep. 30, 2014 Revolving credit facility through December 31, 2013 Maximum	Sep. 30, 2014 Revolving credit facility through maturity Maximum	Sep. 30, 2014 Revolving credit facility Letter of Credit	Sep. 30, 2014 Previous Revolving Credit Facility	Jul. 31, 2014 Previous Revolving Credit Facility	Oct. 28, 2013 Previous Revolving Credit Facility	Sep. 30, 2014 7.25% Senior Notes due 2019	Dec. 31, 2013 7.25% Senior Notes due 2019	Sep. 30, 2014 7.25% Senior Notes due 2019 Group One	Sep. 30, 2014 7.25% Senior Notes due 2019 Group Two	Sep. 30, 2014 Senior Notes due 2020	Dec. 31, 2013 Senior Notes due 2020
Debt Disclosure [Line Items]
Gains (Losses) on Extinguishment of Debt	$ 0	$ 0	$ 0	$ (29,157,000)
Senior Notes, Noncurrent															300,000,000	300,000,000			775,000,000	775,000,000
Line Of Credit Facility Borrowing Base													437,500,000	475,000,000
Maximum borrowing capacity						450,000,000					20,000,000
Optional additional borrowing					150,000,000
Letter of credit amount outstanding												1,700,000
Available borrowing capacity												$ 435,800,000
Credit facility interest rate option one, applicable margin rate over Adjusted LIBOR							1.50%	2.50%
Credit facility interest rate option two, base rate over federal funds effective rate					0.50%
Debt Instrument, Description of Variable Rate Basis			one-month Adjusted LIBOR
Credit facility interest rate option two, base rate over one-month Adjusted LIBOR					1.00%
Credit facility interest rate option two, applicable margin rate					1.50%		0.50%	1.50%
Commitment fees for undrawn credit facility							0.375%	0.50%
LIne of Credit Facility, Commitment Fee Percentage at Period End					0.375%
Line of Credit Facility, Interest Rate at Period End					1.6875%
Line of Credit Facility, Interest Rate at Period End, LIBOR component					0.1875%
Current ratio							1.0
Debt to EBITDAX ratio									4.25	4.0
Annual interest rate															7.25%				8.50%
Redemption option, percent of principal																	103.625%	100.00%

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Shareholders' Equity - Additional Information (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended			9 Months Ended					9 Months Ended			3 Months Ended	9 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013		Jun. 10, 2014	Sep. 30, 2014 Depositary Shares	Sep. 30, 2014 Series A Preferred Stock	Dec. 31, 2013 Series A Preferred Stock	Sep. 30, 2014 Series B Preferred Stock	Sep. 30, 2014 Series B Preferred Stock	Sep. 30, 2014 Convertible Preferred Stock
Class of Stock [Line Items]
Preferred Stock, Shares Issued										7,945	11,500	32,500	32,500
Stockholders' Equity, Other				$ 488	[1]	$ (46,563)	[1]
Preferred Stock Conversions, Inducements	888		0	4,256		0				4,300
Conversion of Stock, Shares Converted for Inducement Consideration										3,527
Preferred stock dividends (in dollars per share)										$ 450			$ 198
Preferred stock dividend rate										6.00%			6.00%
Proceeds from Issuance of Convertible Preferred Stock	313,000			313,330		0
Conversion of Stock, Shares Converted									355,482					3,555
Other Comprehensive loss, pension and postretirements obligations, before tax				114		86
Change in pension and postretirement obligations, net of tax	$ 14		$ 10	$ 40		$ 30
Depositary Shares Issued During Period, New Issues		3,250,000
Depositary Share Interest in a Share of 6.00% Convertible Perpetual Preferred Stock, Series B	0.01
Stock Issued During Period, Shares, New Issues												32,500
Preferred Stock, Liquidation Preference Per Share	$ 10,000			$ 10,000
Conversion Price per Share	$ 18.34			$ 18.34
Convertible Preferred Stock, Shares Issued upon Conversion	545.17
Premium, Conversion Price to Common Share Closing Price Prior to Series B Preferred Stock Offering								30.00%
Common Share Price, Last Reported Prior to Series B Preferred Stock Offering								$ 14.11
Premium, Conversion Ratio into Common Stock if Closing Sale Price Exceed Prior Period Conversion Price	130.00%			130.00%

[1] Includes equity-classified share-based compensation of $2,638 and $4,781 for the nine months ended September 30, 2014 and 2013.

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Summary of Property and Equipment (Detail) (USD $)	3 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Apr. 24, 2013
Property, Plant and Equipment [Line Items]
Impairment of Oil and Gas Properties	$ 6,100,000
Impairment of Long-Lived Assets to be Disposed of		117,900,000
Oil and gas properties:
Proved	450,601,000		460,255,000
Unproved	137,464,000		101,520,000
Total oil and gas properties	588,065,000		561,775,000
Capitalized Costs, Proved Properties	2,743,466,000		2,593,700,000	267,688,000
Capitalized Costs, Support Equipment and Facilities	23,153,000		21,513,000
Property, Plant and Equipment, Other, Gross	2,766,619,000		2,615,213,000
Properties and equipment, gross, total	3,354,684,000		3,176,988,000
Accumulated depreciation, depletion and amortization	(1,011,781,000)		(939,684,000)
Property and equipment, net (successful efforts method)	$ 2,342,903,000		$ 2,237,304,000

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Share-Based Compensation Expense

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014			2013		2014		2013
Equity-classified awards:
Stock option awards	$	403		$	612	$	1,193	$	2,518
Common, deferred and restricted stock and stock unit awards	584			398		1,445		2,263
	987			1,010		2,638		4,781
Liability-classified awards	(360		)	1,095		6,632		1,544
	$	627		$	2,105	$	9,270	$	6,325

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Restructuring and Exit Activities - Additional Information (Detail) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Restructuring reserve, noncurrent	$ 12,352,000	$ 13,245,000
Accounts Payable and Accrued Liabilities
Restructuring Cost and Reserve [Line Items]
Restructuring reserve, current	2,700,000
Other Noncurrent Liabilities
Restructuring Cost and Reserve [Line Items]
Restructuring reserve, noncurrent	$ 12,400,000

XML

Acquisition and Divestitures (Tables)

9 Months Ended

Sep. 30, 2014

Acquisitions and Divestitures [Abstract]

Business Acquisition, Purchase Price Allocation [Table Text Block]

The following table represents the fair values assigned to the net assets acquired and the consideration paid:

Assets
Oil and gas properties – proved	$	267,688
Oil and gas properties – unproved	119,709
Accounts receivable, net	107,345
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

Business Acquisition, Pro Forma Information [Table Text Block]

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 periods 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.

	Nine Months Ended
	September 30, 2013
Total revenues	$	344,412
Net loss attributable to common shareholders	$	(124,172	)
Loss per share – basic and diluted	$	(1.84	)

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Components of Selected Balance Sheet Accounts (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Other current assets:
Tubular inventory and well materials	$ 3,946	$ 2,271
Prepaid expenses	2,905	3,653
Other Assets, Miscellaneous, Current	100	0
Other Assets, Current	6,951	5,924
Other assets:
Debt issuance costs	27,277	30,239
Assets of supplemental employee retirement plan (“SERP”)	4,021	3,734
Other	562	562
Other assets	31,860	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	105,888	120,278
Drilling and other lease operating costs	56,585	51,529
Royalties	46,672	39,929
Compensation – related	10,947	8,584
Interest	37,417	15,718
Preferred stock dividends	7,638	1,725
Other	11,446	10,241
Accounts payable and accrued liabilities	276,593	248,004
Other liabilities:
Sale Leaseback Transaction Deferred Gain Noncurrent	90,675	0
Firm transportation obligation	12,352	13,245
Asset retirement obligations (“AROs”)	5,808	6,437
Defined benefit pension obligations	1,461	1,579
Postretirement health care benefit obligations	1,154	1,023
Deferred compensation – SERP obligations and other	4,130	3,883
Other	10,066	7,219
Other liabilities	$ 125,646	$ 33,386

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Derivative Instruments - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified						9 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 7.25% Senior Unsecured Notes due 2019	Sep. 30, 2014 Commodity contracts Entity	Sep. 30, 2014 Commodity contracts Credit Concentration Risk Entity	Sep. 30, 2014 Commodity contracts Natural Gas	Sep. 30, 2014 Commodity contracts Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices						NYMEX Henry Hub gas	West Texas Intermediate crude oil
Annual interest rate			7.25%
Derivative assets	$ 22,252	$ 5,382		$ 22,300
Number of derivative counterparties				7	2

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Acquisitions and Divestitures Purchase Price Allocation (Details) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	0 Months Ended	3 Months Ended	4 Months Ended	9 Months Ended
	Apr. 24, 2013	Jun. 30, 2013	Apr. 24, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Acquisitions and Divestitures [Abstract]
Business Acquisition, Total Consideration Transferred, Net of Proceeds From Investing Partners	$ 380,000,000
Business Acquisition, Purchase Price Adjustments, Effective Date to Date of Acquisition			19,000,000
Stock Issued During Period, Shares, Acquisitions	10
Stock Issued during period, Fair Value per Share, Acquisitions	$ 4.23		$ 4.23
Proceeds From Joint Interest Partners Upon Exercise of Preferential Rights Related to the Acquisition		21,000,000
BusinessAcquisition, Oil and Gas Properties - Proved	267,688,000		267,688,000	2,743,466,000		2,593,700,000
BusinessAcquisitionsPurchasePriceAllocationUnprovedOilandGasProperties	119,709,000		119,709,000
Business Acquisition, Purchase Price Allocation, Current Assets, Receivables	107,345,000		107,345,000
Business Acquisition, Purchase Price Allocation, Current Assets, Prepaid Expense and Other Assets	2,068,000		2,068,000
Business Acquisition, Purchase Price Allocation, Assets Acquired	496,810,000		496,810,000
Business Acquisition, Purchase Price Allocation, Current Liabilities, Accounts Payable	94,771,000		94,771,000
Business Acquisition, Purchase Price Allocation, Current Liabilities, Accrued Liabilities	1,500,000		1,500,000
Business Acquisition, Purchase Price Allocation, Liabilities Assumed	96,271,000		96,271,000
Business Acquisition, Purchase Price Allocation, Assets Acquired (Liabilities Assumed), Net	400,539,000		400,539,000
Cash Payments To Acquire Business, Net of Amounts Received for Preferential Rights	358,239,000			0	358,239,000
Stock Issued During Period, Value, Acquisitions	42,300,000
Business Combination, Consideration Transferred	$ 400,539,000

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Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Assets:
Commodity derivative assets – current	$ 13,680	$ 3,830
Commodity derivative assets – noncurrent	8,572	1,552
Liabilities:
Commodity derivative liabilities – current	(1,045)	(10,141)
Commodity derivative liabilities – noncurrent	0	0
Fair Value, Measurements, Recurring | Estimate of Fair Value, Fair Value Disclosure [Member]
Assets:
Assets of SERP	4,021	3,734
Liabilities:
Deferred compensation – SERP obligations	(4,125)	(3,879)
Fair Value, Measurements, Recurring | Level 1
Assets:
Assets of SERP	4,021	3,734
Liabilities:
Deferred compensation – SERP obligations	(4,125)	(3,879)
Fair Value, Measurements, Recurring | Level 2
Assets:
Assets of SERP	0	0
Liabilities:
Deferred compensation – SERP obligations	0	0
Fair Value, Measurements, Recurring | Level 3
Assets:
Assets of SERP	0	0
Liabilities:
Deferred compensation – SERP obligations	0	0
Fair Value, Measurements, Recurring | Commodity contracts | Estimate of Fair Value, Fair Value Disclosure [Member]
Assets:
Commodity derivative assets – current	13,680	3,830
Commodity derivative assets – noncurrent	8,572	1,552
Liabilities:
Commodity derivative liabilities – current	(1,045)	(10,141)
Commodity derivative liabilities – noncurrent	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – noncurrent	0	0
Liabilities:
Commodity derivative liabilities – current	0	0
Commodity derivative liabilities – noncurrent	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Assets:
Commodity derivative assets – current	13,680	3,830
Commodity derivative assets – noncurrent	8,572	1,552
Liabilities:
Commodity derivative liabilities – current	(1,045)	(10,141)
Commodity derivative liabilities – noncurrent	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – noncurrent	0	0
Liabilities:
Commodity derivative liabilities – current	0	0
Commodity derivative liabilities – noncurrent	$ 0

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Summary of Long-Term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Revolving credit facility	$ 0	$ 206,000
Total	1,075,000	1,281,000
7.25% Senior Notes due 2019
Debt Instrument [Line Items]
Senior notes	300,000	300,000
8.5% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	$ 775,000	$ 775,000

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Basis of Presentation

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Basis of Presentation

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, 2013. Operating results for the nine months ended September 30, 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.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014-09 on our ongoing financial reporting.

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 an increase in the borrowing base under our revolving credit facility (the “Revolver”) as discussed in Note 7, 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.

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Commodity Derivative Positions (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Sep. 30, 2014 bbl
Settlements to be received (paid) in subsequent period
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset	$ 52
Fair Value Liability	0
Crude Oil | Group One
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Derivative, Nonmonetary Notional Amount	2,000
Weighted Average Price, Floor/Swap	90.00
Weighted Average Price, Ceiling	94,330.00
Fair Value Asset	264
Fair Value Liability	0
Crude Oil | Group Two
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Derivative, Nonmonetary Notional Amount	4,000
Weighted Average Price, Floor/Swap	87.50
Weighted Average Price, Ceiling	94,660.00
Fair Value Asset	649
Fair Value Liability	0
Crude Oil | Group Three
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Derivative, Nonmonetary Notional Amount	4,000
Weighted Average Price, Floor/Swap	87.50
Weighted Average Price, Ceiling	94,660.00
Fair Value Asset	947
Fair Value Liability	0
Crude Oil | Group Four
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Derivative, Nonmonetary Notional Amount	3,000
Weighted Average Price, Floor/Swap	86.67
Weighted Average Price, Ceiling	94,730.00
Fair Value Asset	770
Fair Value Liability	0
Crude Oil | Group Five
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Derivative, Nonmonetary Notional Amount	3,000
Weighted Average Price, Floor/Swap	86.67
Weighted Average Price, Ceiling	94,730.00
Fair Value Asset	838
Fair Value Liability	0
Crude Oil | Group Six
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	11,000
Derivative, Swap Type, Average Fixed Price	93.45
Fair Value Asset	3,301
Fair Value Liability	40
Crude Oil | Group Seven
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	9,000
Derivative, Swap Type, Average Fixed Price	91.81
Fair Value Asset	2,197
Fair Value Liability	0
Crude Oil | Group Eight
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	9,000
Derivative, Swap Type, Average Fixed Price	91.81
Fair Value Asset	2,835
Fair Value Liability	0
Crude Oil | Group Nine
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	8,000
Derivative, Swap Type, Average Fixed Price	91.06
Fair Value Asset	2,352
Fair Value Liability	0
Crude Oil | Group Ten
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	8,000
Derivative, Swap Type, Average Fixed Price	91.06
Fair Value Asset	2,432
Fair Value Liability	0
Crude Oil | Group Eleven
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	3,000
Derivative, Swap Type, Average Fixed Price	90.84
Fair Value Asset	1,176
Fair Value Liability	0
Crude Oil | Group Twelve
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	3,000
Derivative, Swap Type, Average Fixed Price	90.84
Fair Value Asset	1,284
Fair Value Liability	0
Crude Oil | Group Thirteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	3,000
Derivative, Swap Type, Average Fixed Price	90.84
Fair Value Asset	1,395
Fair Value Liability	0
Crude Oil | Group Fourteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Derivative, Nonmonetary Notional Amount	3,000
Derivative, Swap Type, Average Fixed Price	90.84
Fair Value Asset	1,447
Fair Value Liability	0
Crude Oil | Group Fifteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaptions
Derivative, Nonmonetary Notional Amount	1,000
Derivative, Average Price Risk Option Strike Price	88.00
Fair Value Asset	0
Fair Value Liability	252
Crude Oil | Group Sixteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaptions
Derivative, Nonmonetary Notional Amount	1,000
Derivative, Average Price Risk Option Strike Price	88.00
Fair Value Asset	0
Fair Value Liability	251
Crude Oil | Group Seventeen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaptions
Derivative, Nonmonetary Notional Amount	1,000
Derivative, Average Price Risk Option Strike Price	88.00
Fair Value Asset	0
Fair Value Liability	251
Crude Oil | Group Eighteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaptions
Derivative, Nonmonetary Notional Amount	1,000
Derivative, Average Price Risk Option Strike Price	88.00
Fair Value Asset	0
Fair Value Liability	251
Natural Gas | Group Nineteen
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Average Volume Per Day (MMBtu)	5,000
Weighted Average Price, Floor/Swap	4.50
Fair Value Asset	185
Fair Value Liability	0
Natural Gas | Group Twenty
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Average Volume Per Day (MMBtu)	5,000
Weighted Average Price, Floor/Swap	4.50
Fair Value Asset	129
Fair Value Liability	$ 0

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Carrying Amount of Components of Long-term Debt

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

	As of
	September 30,		December 31,
	2014		2013
Revolving credit facility	$	—	$	206,000
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		775,000
	$	1,075,000	$	1,281,000

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Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Summary of Property and Equipment

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

	As of
	September 30,			December 31,
	2014			2013
Oil and gas properties:
Proved	$	450,601		$	460,255
Unproved	137,464			101,520
Total oil and gas properties	588,065			561,775
Other property and equipment:
Wells, equipment and facilities	2,743,466			2,593,700
Support equipment	23,153			21,513
Total other property and equipment	2,766,619			2,615,213
	3,354,684			3,176,988
Accumulated depreciation, depletion and amortization	(1,011,781		)	(939,684		)
	$	2,342,903		$	2,237,304

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Summary of Share-Based Compensation Expense (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock option awards	$ 403	$ 612	$ 1,193	$ 2,518
Common, deferred, restricted and restricted unit awards	584	398	1,445	2,263
Share-based compensation			2,638	4,781
Allocated Share-based Compensation Expense	627	2,105	9,270	6,325
Equity-classified awards:
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	987	1,010	2,638	4,781
Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	$ (360)	$ 1,095	$ 6,632	$ 1,544

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Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ 66,457	$ (24,035)	$ 8,130	$ (23,208)
Cash received (paid)	(7,557)	(4,165)	(17,836)	1,625
Unrealized gains (losses)	74,014	(19,870)	25,966	(24,833)
Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	66,457	(24,035)	8,130	(23,208)
Derivative, Cash Received on Hedge	7,557	4,165	17,836	(1,625)
Unrealized gains (losses)	74,014	(19,870)	25,966	(24,833)
Interest rate contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	0	0	0	0
Cash received (paid)	0	0	0	0
Unrealized gains (losses)	$ 0	$ 0	$ 0	$ 0

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Additional Balance Sheet Detail (Tables)

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Components of Selected Balance Sheet Accounts

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

	As of
	September 30,		December 31,
	2014		2013
Other current assets:
Tubular inventory and well materials	$	3,946	$	2,271
Prepaid expenses	2,905		3,653
Other	100		—
	$	6,951	$	5,924
Other assets:
Debt issuance costs	$	27,277	$	30,239
Assets of supplemental employee retirement plan (“SERP”)	4,021		3,734
Other	562		562
	$	31,860	$	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	$	105,888	$	120,278
Drilling and other lease operating costs	56,585		51,529
Royalties	46,672		39,929
Compensation – related	10,947		8,584
Interest	37,417		15,718
Preferred stock dividends	7,638		1,725
Other	11,446		10,241
	$	276,593	$	248,004
Other liabilities:
Deferred gains on sale of assets	$	90,675	$	—
Firm transportation obligation	12,352		13,245
Asset retirement obligations (“AROs”)	5,808		6,437
Defined benefit pension obligations	1,461		1,579
Postretirement health care benefit obligations	1,154		1,023
Deferred compensation – SERP obligations and other	4,130		3,883
Other	10,066		7,219
	$	125,646	$	33,386

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Summary of Long-Term Debt with Fixed Interest Rates

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
	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	300,750	$	300,000	$	307,500	$	300,000
Senior Notes due 2020	821,500		775,000		837,969		775,000
	$	1,122,250	$	1,075,000	$	1,145,469	$	1,075,000

Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables summarize the valuation of those assets and liabilities as of the dates presented:

	As of September 30, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets – current	$	13,680		$	—		$	13,680		$	—
Commodity derivative assets – noncurrent	8,572			—			8,572			—
Assets of SERP	4,021			4,021			—			—
Liabilities:
Commodity derivative liabilities – current	(1,045		)	—			(1,045		)	—
Commodity derivative liabilities – noncurrent	—			—			—			—
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—			—

	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		)	—			—

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Organization

9 Months Ended

Sep. 30, 2014

Accounting Policies [Abstract]

Organization

Organization

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 drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma and the Haynesville Shale and Cotton Valley in East Texas.

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Shareholders' Equity (Tables)

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for the nine months ended September 30, 2014 and 2013:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2013			Net Income			Offering		Declared 1			Changes 2			2014
Preferred stock 3	$	1,150		$	—		$	3,250	$	—		$	(356	)	$	4,044
Common stock 3	466			—			—		—			62			528
Paid-in capital 3	891,351			—			310,080		—			3,871			1,205,302
Accumulated deficit 3	(104,180		)	8,102			—		(11,081		)	(4,256		)	(111,415		)
Deferred compensation obligation	2,792			—			—		—			314			3,106
Accumulated other comprehensive income 4	267			—			—		—			74			341
Treasury stock	(3,042		)	—			—		—			(197		)	(3,239		)
	$	788,804		$	8,102		$	313,330	$	(11,081	)	$	(488	)	$	1,098,667
	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2012			Net Loss			Offering		Declared 1			Changes 2			2013
Preferred stock	$	1,150		$	—		$	—	$	—		$	—		$	1,150
Common stock 5	364			—			—		—			101			465
Paid-in capital 5	849,046			—			—		—			46,404			895,450
Retained earnings	45,790			(140,721		)	—		(5,175		)	—			(100,106		)
Deferred compensation obligation	3,111			—			—		—			(384		)	2,727
Accumulated other comprehensive loss 4	(982		)	—			—		—			56			(926		)
Treasury stock	(3,363		)	—			—		—			386			(2,977		)
	$	895,116		$	(140,721	)	$	—	$	(5,175	)	$	46,563		$	795,783

______________________

¹ Includes dividends of $450.00 per share on our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) and $198.33 per share on our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”).

² Includes equity-classified share-based compensation of $2,638 and $4,781 for the nine months ended September 30, 2014 and 2013.

³ A total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5,924,706 shares of our common stock during the nine months ended September 30, 2014. We made payments of $4.3 million to induce the conversion of 3,527 of these shares.

⁴ The Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the nine months ended September 30, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $114 and $86 and are presented above net of taxes of $40 and $30.

⁵ Includes the Shares, with a fair value of $4.23 per share, that were issued to MHR in connection with the EF Acquisition.

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Summary of Accounts Receivable (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Receivables [Abstract]
Customers	$ 97,139	$ 93,288
Joint interest partners	84,112	76,199
Other	7,608	25,538
Accounts Receivable, Gross, Current, Total	188,859	195,025
Less: Allowance for doubtful accounts	(176)	(622)
Accounts receivable, net of allowance for doubtful accounts	$ 188,683	$ 194,403

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Commitments and Contingencies - Additional Information (Detail) (USD $) In Millions, unless otherwise specified		12 Months Ended	9 Months Ended		3 Months Ended
	Sep. 30, 2014	Dec. 31, 2010 Legal Reserve	Sep. 30, 2014 Contract Drilling	Sep. 30, 2014 Maximum Contract Drilling	Sep. 30, 2014 Maximum Firm Transportation	Sep. 30, 2014 Minimum Firm Transportation	Sep. 30, 2014 Gas Gathering And Compression Services	Sep. 30, 2014 Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Contract term				11 months	15 years	1 year
Contract termination claims description			early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their scheduled terms.
Loss on contract termination for default			$ 24.4
Contractual Obligation, Due in Next Twelve Months							3.7
Contractual Obligation, Due in Second Year							4.2
Contractual Obligation, Due in Third Year							5.0
Contractual Obligation								13.7
Reserve established for contingency matters		0.9
Asset retirement obligations	$ 5.8

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Revenues
Crude oil	$ 118,716		$ 100,564		$ 336,382		$ 250,489
Natural gas liquids (NGLs)	9,790		8,212		27,200		22,652
Natural gas	13,354		12,872		47,859		40,465
Gain (Loss) on Disposition of Property Plant Equipment	63,520		(186)		120,295		(479)
Other, net	16		151		2,886		1,339
Total revenues	205,396		121,613		534,622		314,466
Operating expenses
Lease operating	15,296		8,457		38,103		24,891
Gathering, processing and transportation	4,893		3,039		11,380		9,598
Production and ad valorem taxes	7,690		6,597		22,505		19,532
General and administrative	11,527		12,677		43,055		39,276
Exploration	1,986		3,957		13,995		18,097
Depreciation, depletion and amortization	71,999		62,450		215,623		178,355
Asset Impairment Charges	6,084		132,224		123,992		132,224
Total operating expenses	119,475		229,401		468,653		421,973
Operating income (loss)	85,921		(107,788)		65,969		(107,507)
Other income (expense)
Interest expense	(21,953)		(20,218)		(67,716)		(56,505)
Gains (Losses) on Extinguishment of Debt	0		0		0		(29,157)
Derivatives	66,457		(24,035)		8,130		(23,208)
Other	1,349		35		1,380		79
Income (loss) before income taxes	131,774		(152,006)		7,763		(216,298)
Income tax (expense) benefit	(42,113)		53,106		339		75,577
Net income (loss)	89,661		(98,900)		8,102		(140,721)
Preferred stock dividends	(7,641)	[1]	(1,725)	[1]	(11,081)	[1]	(5,175)	[1]
Preferred Stock Conversions, Inducements	(888)		0		(4,256)		0
Net income (loss) attributable to common shareholders	$ 81,132		$ (100,625)		$ (7,235)		$ (145,896)
Net income (loss) per share:
Basic (in dollars per share)	$ 1.13		$ (1.54)		$ (0.11)		$ (2.38)
Diluted (in dollars per share)	$ 0.87		$ (1.54)		$ (0.11)		$ (2.38)
Weighted average shares outstanding – basic	71,536		65,465		67,909		61,272
Weighted average shares outstanding – diluted	103,606		65,465		67,909		61,272

[1] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

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Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 13,680	$ 3,830
Derivative assets, noncurrent	8,572	1,552
Derivative assets	22,252	5,382
Derivative liabilities, current	1,045	10,141
Derivative liabilities, noncurrent	0	0
Derivative liabilities	1,045	10,141
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	22,300
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	13,680	3,830
Derivative liabilities, current	1,045	10,141
Commodity contracts | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	8,572	1,552
Derivative liabilities, noncurrent	0	0
Interest rate contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	0	0
Derivative liabilities, current	0	0
Interest rate contracts | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	0	0
Derivative liabilities, noncurrent	$ 0	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 100	$ 100
Preferred stock, shares authorized	100,000	100,000
Preferred stock, redemption value per share (in dollars per share)	$ 10,000	$ 10,000
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	128,000,000	128,000,000
Common stock, shares issued	71,557,951	65,306,748
Treasury stock, shares	246,352	233,063
Series A Preferred Stock
Statement of Financial Position [Abstract]
Preferred stock, issued	7,945	11,500
Series B Preferred Stock
Statement of Financial Position [Abstract]
Preferred stock, issued	32,500

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Components of Interest Expense (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Banking and Thrift [Abstract]
Interest on borrowings and related fees	$ 22,559	$ 22,754	$ 69,477	$ 57,239
Accretion of original issue discount 1	0	0	0	431
Amortization of debt issuance costs	1,063	961	3,114	2,415
Capitalized interest	(1,669)	(3,497)	(4,875)	(3,580)
Interest expense	$ 21,953	$ 20,218	$ 67,716	$ 56,505

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Interest Expense (Tables)

9 Months Ended

Sep. 30, 2014

Banking and Thrift [Abstract]

Interest Expense Net Disclosure

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Interest on borrowings and related fees	$	22,559		$	22,754		$	69,477		$	57,239
Accretion of original issue discount 1	—			—			—			431
Amortization of debt issuance costs	1,063			961			3,114			2,415
Capitalized interest	(1,669		)	(3,497		)	(4,875		)	(3,580		)
	$	21,953		$	20,218		$	67,716		$	56,505

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Interest Expense

9 Months Ended

Sep. 30, 2014

Banking and Thrift [Abstract]

Interest Expense

Interest Expense

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Interest on borrowings and related fees	$	22,559		$	22,754		$	69,477		$	57,239
Accretion of original issue discount 1	—			—			—			431
Amortization of debt issuance costs	1,063			961			3,114			2,415
Capitalized interest	(1,669		)	(3,497		)	(4,875		)	(3,580		)
	$	21,953		$	20,218		$	67,716		$	56,505

_____________________

¹ Represents accretion of original issue discount attributable to our 10.375% Senior Notes due 2016 that were retired in 2013.

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Components of Calculation of Basic and Diluted 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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income (loss)	$	89,661		$	(98,900	)	$	8,102		$	(140,721	)
Less: Preferred stock dividends	(7,641		)	(1,725		)	(11,081		)	(5,175		)
Less: Induced conversion of preferred stock	(888		)	—			(4,256		)	—
Net income (loss) attributable to common shareholders – basic	$	81,132		$	(100,625	)	$	(7,235	)	$	(145,896	)
Add: Preferred stock dividends 1	7,641			—			—			—
Add: Induced conversion of preferred stock 1	888			—			—			—
Net income (loss) attributable to common shareholders – diluted	$	89,661		$	(100,625	)	$	(7,235	)	$	(145,896	)
Weighted-average shares – basic	71,536			65,465			67,909			61,272
Effect of dilutive securities 2	32,070			—			—			—
Weighted-average shares – diluted	103,606			65,465			67,909			61,272

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2014, approximately 24.9 million potentially dilutive securities, including the Series A Preferred Stock and Series B 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. For the three and nine months ended September 30, 2013, approximately 19.2 million and less than 0.1 million, respectively, potentially dilutive securities, including the Series A 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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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2014

Schedule of Policies [Line Items]

Basis of Presentation

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, 2013. Operating results for the nine months ended September 30, 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.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which requires an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. ASU 2014-09 will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective on January 1, 2017. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014-09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014-09 on our ongoing financial reporting.

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 an increase in the borrowing base under our revolving credit facility (the “Revolver”) as discussed in Note 7, 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.

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.

Fair Value, Measurements, Recurring

Schedule of Policies [Line Items]

Fair Value Measurements

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: 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.

Fair Value, Measurements, Nonrecurring

Schedule of Policies [Line Items]

Fair Value Measurements

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.

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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Cash flows from operating activities
Net income (loss)	$ 8,102	$ (140,721)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss on Extinguishment of Debt	0	29,157
Depreciation, depletion and amortization	215,623	178,355
Asset Impairment Charges	123,992	132,224
Accretion of firm transportation obligation	991	1,263
Derivative contracts:
Net losses (gains)	(8,130)	23,208
Cash settlements, net	(17,836)	1,625
Deferred income tax benefit	(339)	(75,577)
(Gain) loss on sales of assets, net	(120,295)	479
Non-cash exploration expense	8,387	14,167
Non-cash interest expense	3,114	2,846
Share-based compensation (equity-classified)	2,638	4,781
Other, net	325	198
Changes in operating assets and liabilities, net	(16,122)	52,829
Net cash provided by operating activities	200,450	224,834
Cash flows from investing activities
Payments to Acquire Businesses, Net of Cash Acquired	0	(358,239)
Payments To Settle Obligations Assumed In Acquisition Net	33,712	(43,023)
Capital expenditures – property and equipment	(545,031)	(356,964)
Proceeds from Sale of Productive Assets	311,913	653
Net cash used in investing activities	(199,406)	(757,573)
Cash flows from financing activities
Proceeds from Issuance of Convertible Preferred Stock	313,330	0
Payments Made To Induce Conversion Of Preferred Stock	(4,256)	0
Proceeds from Issuance of Senior Long-term Debt	0	775,000
Repayments of Debt	0	(319,090)
Proceeds from revolving credit facility borrowings	377,000	219,000
Repayment of revolving credit facility borrowings	(583,000)	(91,000)
Payments of Debt Issuance Costs	(151)	(25,199)
Dividends paid on preferred stock	(5,165)	(5,137)
Other, net	1,414	(164)
Net cash provided by financing activities	99,172	553,410
Net increase in cash and cash equivalents	100,216	20,671
Cash and cash equivalents - beginning of period	23,474	17,650
Cash and cash equivalents - end of period	123,690	38,321
Cash paid for:
Interest	47,778	24,251
Income taxes	$ 100	$ 0

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 89,661	$ (98,900)	$ 8,102	$ (140,721)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $14 and $40 in 2014 and $10 and $30 in 2013	25	18	74	56
Total Other Comprehensive Income (Loss), Net of Tax	25	18	74	56
Comprehensive income (loss)	$ 89,686	$ (98,882)	$ 8,176	$ (140,665)

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Fair Value Measurements

9 Months Ended

Sep. 30, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

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 September 30, 2014, 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
	September 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	300,750	$	300,000	$	307,500	$	300,000
Senior Notes due 2020	821,500		775,000		837,969		775,000
	$	1,122,250	$	1,075,000	$	1,145,469	$	1,075,000

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 September 30, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets – current	$	13,680		$	—		$	13,680		$	—
Commodity derivative assets – noncurrent	8,572			—			8,572			—
Assets of SERP	4,021			4,021			—			—
Liabilities:
Commodity derivative liabilities – current	(1,045		)	—			(1,045		)	—
Commodity derivative liabilities – noncurrent	—			—			—			—
Deferred compensation – SERP obligations	(4,125		)	(4,125		)	—			—

	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 nine months ended September 30, 2014 and 2013.

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: 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 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.

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Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 24, 2014
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Trading Symbol	PVA
Entity Registrant Name	PENN VIRGINIA CORP
Entity Central Index Key	0000077159
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		71,558,867

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

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 remaining terms of up to 11 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 scheduled terms. The amount of penalty is based on the number of days remaining in the contractual term. As of September 30, 2014, the penalty amount would have been $24.4 million had we terminated our agreements on that date.

Other Commitments

We have 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.

We have a long-term agreement that provides natural gas gathering, compression and gas lift services for a substantial portion of our natural gas 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 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.

As discussed in Note 3, we entered into long-term agreements that provide gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our obligations under the agreements are expected to begin in 2015 when construction of the gathering, transportation and delivery point facilities is completed. The agreements require us to commit certain minimum volumes of crude oil production for the first ten years of the agreements’ terms, which will result in minimum fee requirements of $13.7 million on an annual basis.

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 September 30, 2014. As of September 30, 2014, we also have AROs of approximately $5.8 million attributable to the plugging of abandoned wells.

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]
Change in pension and postretirement obligations, net of tax	$ 14	$ 10	$ 40	$ 30

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Derivative Instruments

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility and, from time to time, the volatility in interest rates attributable to our debt instruments. Our derivative instruments are not formally designated as hedges.

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.

The following table sets forth our commodity derivative positions as of September 30, 2014:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2014	Collars	2,000	$	90.00	94.33	$	264	$	—
First quarter 2015	Collars	4,000	$	87.50	94.66	649		—
Second quarter 2015	Collars	4,000	$	87.50	94.66	947		—
Third quarter 2015	Collars	3,000	$	86.67	94.73	770		—
Fourth quarter 2015	Collars	3,000	$	86.67	94.73	838		—
Fourth quarter 2014	Swaps	11,000	$	93.45		3,301		40
First quarter 2015	Swaps	9,000	$	91.81		2,197		—
Second quarter 2015	Swaps	9,000	$	91.81		2,835		—
Third quarter 2015	Swaps	8,000	$	91.06		2,352		—
Fourth quarter 2015	Swaps	8,000	$	91.06		2,432		—
First quarter 2016	Swaps	3,000	$	90.84		1,176		—
Second quarter 2016	Swaps	3,000	$	90.84		1,284		—
Third quarter 2016	Swaps	3,000	$	90.84		1,395		—
Fourth quarter 2016	Swaps	3,000	$	90.84		1,447		—
First quarter 2015	Swaptions	1,000	$	88.00		—		252
Second quarter 2015	Swaptions	1,000	$	88.00		—		251
Third quarter 2015	Swaptions	1,000	$	88.00		—		251
Fourth quarter 2015	Swaptions	1,000	$	88.00		—		251
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2014	Swaps	5,000	$	4.50		185		—
First quarter 2015	Swaps	5,000	$	4.50		129		—
Settlements to be received in subsequent period						52		—

Interest Rate Swaps

During the nine months ended September 30, 2014 and 2013, we had no interest rate derivative instruments in place.

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Impact by contract type:
Commodity contracts	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Interest rate contracts	—			—			—			—
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	(7,557	)	$	(4,165	)	$	(17,836	)	$	1,625
Interest rate contract settlements	—			—			—			—
	(7,557		)	(4,165		)	(17,836		)	1,625
Gains (losses) attributable to:
Commodity contracts	74,014			(19,870		)	25,966			(24,833		)
Interest rate contracts	—			—			—			—
	74,014			(19,870		)	25,966			(24,833		)
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)

The effects of derivative gains and (losses) and cash settlements of our commodity 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 (gains) and Cash settlements, net captions.

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
		September 30, 2014				December 31, 2013
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	13,680	$	1,045	$	3,830	$	10,141
Interest rate contracts	Derivative assets/liabilities – current	—		—		—		—
		13,680		1,045		3,830		10,141
Commodity contracts	Derivative assets/liabilities – noncurrent	8,572		—		1,552		—
Interest rate contracts	Derivative assets/liabilities – noncurrent	—		—		—		—
		8,572		—		1,552		—
		$	22,252	$	1,045	$	5,382	$	10,141

As of September 30, 2014, we reported a commodity derivative asset of $22.3 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with two 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.

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Accounts Receivable and Major Customers

9 Months Ended

Sep. 30, 2014

Receivables [Abstract]

Accounts Receivable and Major Customers

Accounts Receivable and Major Customers

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

	As of
	September 30,			December 31,
	2014			2013
Customers	$	97,139		$	93,288
Joint interest partners	84,112			76,199
Other 1	7,608			25,538
	188,859			195,025
Less: Allowance for doubtful accounts	(176		)	(622		)
	$	188,683		$	194,403

______________________

¹ The balance as of December 31, 2013 was comprised substantially of amounts due from MHR and other parties for purchase price adjustments attributable to the EF Acquisition, which were received in August 2014.

For the nine months ended September 30, 2014, four customers accounted for $267.0 million, or approximately 65%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2014 were $86.2 million, $72.5 million, $55.8 million and $52.6 million or 21%, 18%, 13% and 13% of the consolidated total, respectively. As of September 30, 2014, $65.2 million, or approximately 67% of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2013, three customers accounted for $124.1 million, or approximately 40% of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2013 were $51.9 million, $37.7 million and $34.5 million or approximately 17%, 12% and 11% of the consolidated total, respectively. As of December 31, 2013, $34.8 million, or approximately 37% 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.

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Earnings per Share

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Earnings per Share

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income (loss)	$	89,661		$	(98,900	)	$	8,102		$	(140,721	)
Less: Preferred stock dividends	(7,641		)	(1,725		)	(11,081		)	(5,175		)
Less: Induced conversion of preferred stock	(888		)	—			(4,256		)	—
Net income (loss) attributable to common shareholders – basic	$	81,132		$	(100,625	)	$	(7,235	)	$	(145,896	)
Add: Preferred stock dividends 1	7,641			—			—			—
Add: Induced conversion of preferred stock 1	888			—			—			—
Net income (loss) attributable to common shareholders – diluted	$	89,661		$	(100,625	)	$	(7,235	)	$	(145,896	)
Weighted-average shares – basic	71,536			65,465			67,909			61,272
Effect of dilutive securities 2	32,070			—			—			—
Weighted-average shares – diluted	103,606			65,465			67,909			61,272

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2014, approximately 24.9 million potentially dilutive securities, including the Series A Preferred Stock and Series B 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. For the three and nine months ended September 30, 2013, approximately 19.2 million and less than 0.1 million, respectively, potentially dilutive securities, including the Series A 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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Shareholders' Equity

9 Months Ended

Sep. 30, 2014

Equity [Abstract]

Shareholders' Equity

Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for the nine months ended September 30, 2014 and 2013:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2013			Net Income			Offering		Declared 1			Changes 2			2014
Preferred stock 3	$	1,150		$	—		$	3,250	$	—		$	(356	)	$	4,044
Common stock 3	466			—			—		—			62			528
Paid-in capital 3	891,351			—			310,080		—			3,871			1,205,302
Accumulated deficit 3	(104,180		)	8,102			—		(11,081		)	(4,256		)	(111,415		)
Deferred compensation obligation	2,792			—			—		—			314			3,106
Accumulated other comprehensive income 4	267			—			—		—			74			341
Treasury stock	(3,042		)	—			—		—			(197		)	(3,239		)
	$	788,804		$	8,102		$	313,330	$	(11,081	)	$	(488	)	$	1,098,667
	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2012			Net Loss			Offering		Declared 1			Changes 2			2013
Preferred stock	$	1,150		$	—		$	—	$	—		$	—		$	1,150
Common stock 5	364			—			—		—			101			465
Paid-in capital 5	849,046			—			—		—			46,404			895,450
Retained earnings	45,790			(140,721		)	—		(5,175		)	—			(100,106		)
Deferred compensation obligation	3,111			—			—		—			(384		)	2,727
Accumulated other comprehensive loss 4	(982		)	—			—		—			56			(926		)
Treasury stock	(3,363		)	—			—		—			386			(2,977		)
	$	895,116		$	(140,721	)	$	—	$	(5,175	)	$	46,563		$	795,783

______________________

¹ Includes dividends of $450.00 per share on our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) and $198.33 per share on our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”).

² Includes equity-classified share-based compensation of $2,638 and $4,781 for the nine months ended September 30, 2014 and 2013.

³ A total of 3,555 shares, or 355,482 depositary shares, of the Series A Preferred Stock were converted into 5,924,706 shares of our common stock during the nine months ended September 30, 2014. We made payments of $4.3 million to induce the conversion of 3,527 of these shares.

⁴ The Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the nine months ended September 30, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $114 and $86 and are presented above net of taxes of $40 and $30.

⁵ Includes the Shares, with a fair value of $4.23 per share, that were issued to MHR in connection with the EF Acquisition.

In June 2014, we completed a private offering of 3,250,000 depositary shares each representing a 1/100^th interest in a share, or 32,500 shares, of our Series B Preferred Stock, which provided approximately $313 million of proceeds, net of underwriting fees and issuance costs.

The annual dividend on each share of the Series B 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 Series B 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 $18.34 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 545.17 shares of our common stock for each share of the Series B Preferred Stock. The initial conversion price represents a premium of 30 percent relative to the last reported sales price of $14.11 per common share prior to the offering of the Series B Preferred Stock. The Series B Preferred Stock is not redeemable by us or the holders at any time. At any time on or after July 15, 2019, we may, at our option, cause all outstanding shares of the Series B 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 Series B 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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Income Taxes

9 Months Ended

Sep. 30, 2014

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

We recognized an income tax benefit for the nine months ended September 30, 2014 at an effective rate of 4.4%. The annual effective tax rate applied to the nine months ended September 30, 2014 includes federal taxes at the statutory rate of 35%; however, the federal effect is almost entirely offset by state income tax effects, which include a deferred tax benefit associated with an expected decrease in the effective state income tax rate in future periods. The benefit is due primarily to a shift in the source of our expected future state taxable income as a result of the recent sale of all of our properties in Mississippi. Our effective tax rate also 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 asset.

Due to the losses incurred during the three and nine months endedSeptember 30, 2013, we recognized income tax benefits at an effective 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.

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Components of Calculation of Basic and Diluted Earnings Per Share (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Earnings Per Share [Abstract]
Net income (loss)	$ 89,661		$ (98,900)		$ 8,102		$ (140,721)
Less: Preferred stock dividends	(7,641)	[1]	(1,725)	[1]	(11,081)	[1]	(5,175)	[1]
Preferred Stock Conversions, Inducements	(888)		0		(4,256)		0
Net income (loss) attributable to common shareholders, Basic	81,132		(100,625)		(7,235)		(145,896)
Other Preferred Stock Dividends and Adjustments	888
Net income (loss) attributable to common shareholders, Diluted	$ 89,661		$ (100,625)		$ (7,235)		$ (145,896)
Weighted-average shares – Basic	71,536,000		65,465,000		67,909,000		61,272,000
Effect of dilutive securities	32,070,000	[2]	0	[2]	0	[2]	0	[2]
Weighted-average shares – Diluted	103,606,000		65,465,000		67,909,000		61,272,000
Potentially dilutive securities with the effect of being anti-dilutive excluded from the calculation of diluted earnings per common share			19,200,000		24,900,000		100,000

[1] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from diluted earnings per share for the nine months ended September 30, 2014 and the three and nine months ended September 30, 2013 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

[2] For the nine months ended September 30, 2014, approximately 24.9 million potentially dilutive securities, including the Series A Preferred Stock and Series B 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. For the three and nine months ended September 30, 2013, approximately 19.2 million and less than 0.1 million, respectively, potentially dilutive securities, including the Series A 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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Property and Equipment

9 Months Ended

Sep. 30, 2014

Property, Plant and Equipment [Abstract]

Property and Equipment

Property and Equipment

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

	As of
	September 30,			December 31,
	2014			2013
Oil and gas properties:
Proved	$	450,601		$	460,255
Unproved	137,464			101,520
Total oil and gas properties	588,065			561,775
Other property and equipment:
Wells, equipment and facilities	2,743,466			2,593,700
Support equipment	23,153			21,513
Total other property and equipment	2,766,619			2,615,213
	3,354,684			3,176,988
Accumulated depreciation, depletion and amortization	(1,011,781		)	(939,684		)
	$	2,342,903		$	2,237,304

In the three months ended September 30, 2014, we recognized an oil and gas asset impairment of $6.1 million in connection with an exploration prospect drilled in the Mid-Continent region. In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets in Mississippi. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 to write these assets down to fair value. The sale was completed in July 2014.

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Long-Term Debt

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

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

	As of
	September 30,		December 31,
	2014		2013
Revolving credit facility	$	—	$	206,000
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		775,000
	$	1,075,000	$	1,281,000

Revolving Credit Facility

The Revolver provides for a $450 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $150 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. Upon the closing of the sale of our Selma Chalk assets in the third quarter of 2014, the borrowing base was reduced from $475 million to $437.5 million. In October 2014, the borrowing base was increased to $500 million in connection with the regular semi-annual redetermination. The next semi-annual redetermination is scheduled for May 2015. In addition, the Revolver was amended to clarify the requirements with respect to pro forma treatment of material acquisitions and dispositions for purposes of the leverage ratio covenant under the Revolver. 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 September 30, 2014. As of September 30, 2014, our available borrowing capacity under the Revolver was $435.8 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%, plus, in each case, 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 September 30, 2014, the actual interest rate on the outstanding borrowings under the Revolver was 1.6875% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.50%. 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 September 30, 2014, commitment fees were being charged at a rate of 0.375%.

The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries (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 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 leverage ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.25 to 1.0 through December 31, 2014 and then 4.0 to 1.0 through maturity.

2019 Senior Notes

Our 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 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

Our 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 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 2019 Senior Notes and 2020 Senior Notes 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 to obtain funds from the Guarantor Subsidiaries through dividends, advances or loans.

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Additional Balance Sheet Detail

9 Months Ended

Sep. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Additional Balance Sheet Detail

Additional Balance Sheet Detail

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

	As of
	September 30,		December 31,
	2014		2013
Other current assets:
Tubular inventory and well materials	$	3,946	$	2,271
Prepaid expenses	2,905		3,653
Other	100		—
	$	6,951	$	5,924
Other assets:
Debt issuance costs	$	27,277	$	30,239
Assets of supplemental employee retirement plan (“SERP”)	4,021		3,734
Other	562		562
	$	31,860	$	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	$	105,888	$	120,278
Drilling and other lease operating costs	56,585		51,529
Royalties	46,672		39,929
Compensation – related	10,947		8,584
Interest	37,417		15,718
Preferred stock dividends	7,638		1,725
Other	11,446		10,241
	$	276,593	$	248,004
Other liabilities:
Deferred gains on sale of assets	$	90,675	$	—
Firm transportation obligation	12,352		13,245
Asset retirement obligations (“AROs”)	5,808		6,437
Defined benefit pension obligations	1,461		1,579
Postretirement health care benefit obligations	1,154		1,023
Deferred compensation – SERP obligations and other	4,130		3,883
Other	10,066		7,219
	$	125,646	$	33,386

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Restructuring and Exit Activities (Tables)

9 Months Ended

Sep. 30, 2014

Restructuring and Related Activities [Abstract]

Summary of Restructuring Related Obligations

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Balance at beginning of period	$	15,559		$	16,677		$	16,090		$	17,263
Employee, office and other costs accrued, net	18			2			27			5
Accretion of firm transportation obligation	407			410			991			1,263
Cash payments, net	(857		)	(705		)	(1,981		)	(2,147		)
Balance at end of period	$	15,127		$	16,384		$	15,127		$	16,384

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Fair Value Summary of Long-Term Debt with Fixed Interest Rates (Detail) (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	$ 1,122,250	$ 1,145,469
Fair Value | 7.25% Senior Notes due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	300,750	307,500
Fair Value | 8.5% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	821,500	837,969
Carrying Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	1,075,000	1,075,000
Carrying Value | 7.25% Senior Notes due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	300,000	300,000
Carrying Value | 8.5% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	$ 775,000	$ 775,000

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Restructuring and Exit Activities

9 Months Ended

Sep. 30, 2014

Restructuring and Related Activities [Abstract]

Restructuring and Exit Activities

Restructuring and Exit Activities

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

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Balance at beginning of period	$	15,559		$	16,677		$	16,090		$	17,263
Employee, office and other costs accrued, net	18			2			27			5
Accretion of firm transportation obligation	407			410			991			1,263
Cash payments, net	(857		)	(705		)	(1,981		)	(2,147		)
Balance at end of period	$	15,127		$	16,384		$	15,127		$	16,384

Restructuring charges are included in the General and administrative caption on our Condensed Consolidated Statements of Operations. The accretion of the firm transportation 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 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 September 30, 2014, $2.7 million of the total obligations are classified as current while the remaining $12.4 million are classified as noncurrent.

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Accounts Receivable and Major Customers (Tables)

9 Months Ended

Sep. 30, 2014

Receivables [Abstract]

Summary of Accounts Receivable

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

	As of
	September 30,			December 31,
	2014			2013
Customers	$	97,139		$	93,288
Joint interest partners	84,112			76,199
Other 1	7,608			25,538
	188,859			195,025
Less: Allowance for doubtful accounts	(176		)	(622		)
	$	188,683		$	194,403

______________________

¹ The balance as of December 31, 2013 was comprised substantially of amounts due from MHR and other parties for purchase price adjustments attributable to the EF Acquisition, which were received in August 2014.

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Income Taxes (Details)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation, Percent	4.40%	34.90%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	35.00%

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Accounts Receivable and Major Customers - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	9 Months Ended										12 Months Ended
	Sep. 30, 2014 Sales Revenue Customer Concentration Risk Customer	Sep. 30, 2013 Sales Revenue Customer Concentration Risk Customer	Sep. 30, 2014 Sales Revenue Customer Concentration Risk Major Customer 1	Sep. 30, 2013 Sales Revenue Customer Concentration Risk Major Customer 1	Sep. 30, 2014 Sales Revenue Customer Concentration Risk Major Customer 2	Sep. 30, 2013 Sales Revenue Customer Concentration Risk Major Customer 2	Sep. 30, 2014 Sales Revenue Customer Concentration Risk Major Customer 3	Sep. 30, 2013 Sales Revenue Customer Concentration Risk Major Customer 3	Sep. 30, 2014 Sales Revenue Customer Concentration Risk Major Customer 4	Sep. 30, 2014 Accounts Receivable Credit Concentration Risk	Dec. 31, 2013 Accounts Receivable Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers	4	3
Revenues, major customers	$ 267.0	$ 124.1	$ 86.2	$ 51.9	$ 72.5	$ 37.7	$ 55.8	$ 34.5	$ 52.6
Concentration risk, percentage	65.00%	40.00%	21.00%	17.00%	18.00%	12.00%	13.00%	11.00%	13.00%	67.00%	37.00%
Accounts receivable, major customers										$ 65.2	$ 34.8

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CONDENSED CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets
Cash and cash equivalents	$ 123,690	$ 23,474
Accounts receivable, net of allowance for doubtful accounts	188,683	194,403
Derivative assets	13,680	3,830
Deferred Tax Assets, Net of Valuation Allowance, Current	6,040	6,065
Other current assets	6,951	5,924
Total current assets	339,044	233,696
Property and equipment, net (successful efforts method)	2,342,903	2,237,304
Derivative assets	8,572	1,552
Other assets	31,860	34,535
Total assets	2,722,379	2,507,087
Current liabilities
Accounts payable and accrued liabilities	276,593	248,004
Derivative liabilities	1,045	10,141
Total current liabilities	277,638	258,145
Other liabilities	125,646	33,386
Derivative liabilities	0	0
Deferred income taxes	145,428	145,752
Long-term debt	1,075,000	1,281,000
Commitments and contingencies (Note 11)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,945 and 11,500 shares issued as of September 30, 2014 and December 31, 2013 and Series B – 32,500 shares issued as of September 30, 2014, each with a redemption value of $10,000 per share	4,044	1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 71,557,951 and 65,306,748 shares issued as of September 30, 2014 and December 31, 2013, respectively	528	466
Paid-in capital	1,205,302	891,351
Accumulated deficit	(111,415)	(104,180)
Deferred compensation obligation	3,106	2,792
Accumulated other comprehensive income	341	267
Treasury stock – 246,352 and 233,063 shares of common stock, at cost, as of September 30, 2014 and December 31, 2013, respectively	(3,239)	(3,042)
Total shareholders’ equity	1,098,667	788,804
Total liabilities and shareholders’ equity	$ 2,722,379	$ 2,507,087

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2014

Acquisitions and Divestitures [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

Acquisitions

Undeveloped Eagle Ford Acreage

In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) acres in the Eagle Ford in Lavaca County, Texas. The transaction closed in August 2014 for a purchase price of $45.6 million, of which $34.9 million was paid at closing and the balance of $10.7 million will be paid over the next three years as a drilling carry.

EF Acquisition

On April 24, 2013 (the “Acquisition Date”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford (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 Magnum Hunter Resources Corporation (“MHR”), the seller in the EF Acquisition, 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. Subsequent to the Acquisition Date and through December 31, 2013, we paid a total of $22.5 million, net to settle working capital adjustments assumed in the EF Acquisition.

Commencing December 2013, we were involved in arbitration with MHR. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. In July 2014, we received the arbitrator’s determination, which required MHR to pay us a total of $35.1 million, including purchase price adjustments, revenue suspense funds due to partners and royalty owners and interest ($1.3 million) on the funds since the Acquisition Date. Payment of the arbitration settlement was made by MHR in August 2014.

We accounted for the EF Acquisition by applying the acquisition method of accounting as of the Acquisition Date. The following table represents the fair values assigned to the net assets acquired and the consideration paid:

Assets
Oil and gas properties – proved	$	267,688
Oil and gas properties – unproved	119,709
Accounts receivable, net	107,345
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 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 periods 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.

	Nine Months Ended
	September 30, 2013
Total revenues	$	344,412
Net loss attributable to common shareholders	$	(124,172	)
Loss per share – basic and diluted	$	(1.84	)

Divestitures

In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC (“Republic”) for proceeds of $147.1 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate pipeline transportation services for a substantial portion of our current and future South Texas crude oil and condensate production. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred and will be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be 2015. The deferred gain is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

In July 2014, we sold our Selma Chalk assets in Mississippi for proceeds of $67.9 million, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 with respect to these assets.

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP (“AMID”) for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of our current and future South Texas natural gas production. 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 and $0.3 million of the deferred gain during the three and nine months ended September 30, 2014, respectively. As of September 30, 2014, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $9.9 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

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Summary of Restructuring Related Obligations (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Restructuring Reserve [Roll Forward]
Balance at beginning of period	$ 15,559	$ 16,677	$ 16,090	$ 17,263
Employee, office and other costs accrued, net	18	2	27	5
Accretion of firm transportation obligation	(407)	410	991	1,263
Cash payments, net	(857)	(705)	(1,981)	(2,147)
Balance at end of period	$ 15,127	$ 16,384	$ 15,127	$ 16,384

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Positions

The following table sets forth our commodity derivative positions as of September 30, 2014:

		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2014	Collars	2,000	$	90.00	94.33	$	264	$	—
First quarter 2015	Collars	4,000	$	87.50	94.66	649		—
Second quarter 2015	Collars	4,000	$	87.50	94.66	947		—
Third quarter 2015	Collars	3,000	$	86.67	94.73	770		—
Fourth quarter 2015	Collars	3,000	$	86.67	94.73	838		—
Fourth quarter 2014	Swaps	11,000	$	93.45		3,301		40
First quarter 2015	Swaps	9,000	$	91.81		2,197		—
Second quarter 2015	Swaps	9,000	$	91.81		2,835		—
Third quarter 2015	Swaps	8,000	$	91.06		2,352		—
Fourth quarter 2015	Swaps	8,000	$	91.06		2,432		—
First quarter 2016	Swaps	3,000	$	90.84		1,176		—
Second quarter 2016	Swaps	3,000	$	90.84		1,284		—
Third quarter 2016	Swaps	3,000	$	90.84		1,395		—
Fourth quarter 2016	Swaps	3,000	$	90.84		1,447		—
First quarter 2015	Swaptions	1,000	$	88.00		—		252
Second quarter 2015	Swaptions	1,000	$	88.00		—		251
Third quarter 2015	Swaptions	1,000	$	88.00		—		251
Fourth quarter 2015	Swaptions	1,000	$	88.00		—		251
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2014	Swaps	5,000	$	4.50		185		—
First quarter 2015	Swaps	5,000	$	4.50		129		—
Settlements to be received in subsequent period						52		—

Impact of Derivative Activities on Condensed Consolidated Statements of Income

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Impact by contract type:
Commodity contracts	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Interest rate contracts	—			—			—			—
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	(7,557	)	$	(4,165	)	$	(17,836	)	$	1,625
Interest rate contract settlements	—			—			—			—
	(7,557		)	(4,165		)	(17,836		)	1,625
Gains (losses) attributable to:
Commodity contracts	74,014			(19,870		)	25,966			(24,833		)
Interest rate contracts	—			—			—			—
	74,014			(19,870		)	25,966			(24,833		)
	$	66,457		$	(24,035	)	$	8,130		$	(23,208	)

Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets

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
		September 30, 2014				December 31, 2013
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	13,680	$	1,045	$	3,830	$	10,141
Interest rate contracts	Derivative assets/liabilities – current	—		—		—		—
		13,680		1,045		3,830		10,141
Commodity contracts	Derivative assets/liabilities – noncurrent	8,572		—		1,552		—
Interest rate contracts	Derivative assets/liabilities – noncurrent	—		—		—		—
		8,572		—		1,552		—
		$	22,252	$	1,045	$	5,382	$	10,141

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Acquisitions and Divestitures Business Acquisition, Pro-Forma Information (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	9 Months Ended
	Sep. 30, 2013
Business Acquisition, Pro Forma Information, Nonrecurring Adjustment [Line Items]
Business Acquisition, Pro Forma Revenue	$ 344,412
Business Acquisition, Pro Forma Net Income (Loss)	$ (124,172)
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ (1.84)

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Share-Based Compensation

9 Months Ended

Sep. 30, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Share-Based Compensation

Share-Based Compensation

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.

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

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2014			2013		2014		2013
Equity-classified awards:
Stock option awards	$	403		$	612	$	1,193	$	2,518
Common, deferred and restricted stock and stock unit awards	584			398		1,445		2,263
	987			1,010		2,638		4,781
Liability-classified awards	(360		)	1,095		6,632		1,544
	$	627		$	2,105	$	9,270	$	6,325