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, 2015 

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	ý	Accelerated filer	o
Non-accelerated filer	o	Smaller reporting company	o

 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 November 6, 2015, 73,357,172 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, 2015

Table of Contents

Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2015 and 2014	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2015 and 2014	4
	Condensed Consolidated Balance Sheets as of September 30, 2015 and December 31, 2014	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2015 and 2014	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Divestitures	8
	4. Accounts Receivable and Major Customers	9
	5. Derivative Instruments	9
	6. Property and Equipment	11
	7. Long-Term Debt	11
	8. Income Taxes	13
	9. Firm Transportation Obligation	13
	10. Additional Balance Sheet Detail	13
	11. Fair Value Measurements	15
	12. Commitments and Contingencies	16
	13. Shareholders’ Equity	18
	14. Share-Based Compensation	19
	15. Interest Expense	19
	16. Earnings per Share	20
Forward-Looking Statements		21
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	22
	Key Developments	23
	Financial Condition	26
	Results of Operations	32
	Critical Accounting Estimates	39
3.	Quantitative and Qualitative Disclosures About Market Risk	39
4.	Controls and Procedures	40
Part II - Other Information
1.	Legal Proceedings	41
1A.	Risk Factors
6.	Exhibits	41
Signatures		42

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,
	2015			2014			2015			2014
Revenues
Crude oil	$	51,124		$	118,716		$	180,964		$	336,382
Natural gas liquids (NGLs)	3,254			9,790			13,841			27,200
Natural gas	6,312			13,354			22,143			47,859
Gain on sales of property and equipment, net	50,828			63,520			50,803			120,295
Other, net	466			16			2,376			2,886
Total revenues	111,984			205,396			270,127			534,622
Operating expenses
Lease operating	11,304			14,761			33,780			36,878
Gathering, processing and transportation	5,654			5,428			19,535			12,605
Production and ad valorem taxes	3,483			7,690			13,139			22,505
General and administrative	9,416			11,527			32,865			43,055
Exploration	1,673			1,986			11,922			13,995
Depreciation, depletion and amortization	76,850			71,999			253,056			215,623
Impairments	—			6,084			1,084			123,992
Total operating expenses	108,380			119,475			365,381			468,653
Operating income (loss)	3,604			85,921			(95,254		)	65,969
Other income (expense)
Interest expense	(22,985		)	(21,953		)	(68,021		)	(67,716		)
Derivatives	44,701			66,457			52,073			8,130
Other	(44		)	1,349			(586		)	1,380
Income (loss) before income taxes	25,276			131,774			(111,788		)	7,763
Income tax (expense) benefit	624			(42,113		)	394			339
Net income (loss)	25,900			89,661			(111,394		)	8,102
Preferred stock dividends	(5,935		)	(7,641		)	(18,069		)	(11,081		)
Induced conversion of preferred stock	—			(888		)	—			(4,256		)
Net income (loss) attributable to common shareholders	$	19,965		$	81,132		$	(129,463	)	$	(7,235	)
Net income (loss) per share:
Basic	$	0.27		$	1.13		$	(1.79	)	$	(0.11	)
Diluted	$	0.25		$	0.87		$	(1.79	)	$	(0.11	)
Weighted average shares outstanding – basic	72,651			71,536			72,438			67,909
Weighted average shares outstanding – diluted	103,452			103,606			72,438			67,909

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,
	2015			2014		2015			2014
Net income (loss)	$	25,900		$	89,661	$	(111,394	)	$	8,102
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax of $(6) and $(17) in 2015 and $14 and $40 in 2014	(11		)	25		(32		)	74
	(11		)	25		(32		)	74
Comprehensive income (loss)	$	25,889		$	89,686	$	(111,426	)	$	8,176

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,
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	3,342		$	6,252
Accounts receivable, net of allowance for doubtful accounts	73,020			189,627
Derivative assets	96,211			128,981
Deferred income taxes	—			53
Other current assets	7,302			10,114
Total current assets	179,875			335,027
Property and equipment, net (successful efforts method)	1,818,586			1,825,098
Derivative assets	16,149			35,897
Other assets	5,836			5,841
Total assets	$	2,020,446		$	2,201,863
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	161,908		$	312,227
Derivative liabilities	—			—
Total current liabilities	161,908			312,227
Other liabilities	105,237			123,886
Deferred income taxes	4,868			4,504
Long-term debt, net of unamortized issuance costs	1,193,362			1,085,429
Commitments and contingencies (Note 12)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,070 shares and 7,945 shares issued as of September 30, 2015 and December 31, 2014, respectively, and Series B – 32,500 shares issued as of September 30, 2015 and December 31, 2014, each with a redemption value of $10,000 per share	3,957			4,044
Common stock of $0.01 par value – 228,000,000 shares authorized; 73,297,205 and 71,568,936 shares issued as of September 30, 2015 and December 31, 2014, respectively	548			529
Paid-in capital	1,209,187			1,206,305
Accumulated deficit	(658,704		)	(535,176		)
Deferred compensation obligation	3,440			3,211
Accumulated other comprehensive income	217			249
Treasury stock – 455,689 and 262,070 shares of common stock, at cost, as of September 30, 2015 and December 31, 2014, respectively	(3,574		)	(3,345		)
Total shareholders’ equity	555,071			675,817
Total liabilities and shareholders’ equity	$	2,020,446		$	2,201,863

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,
	2015			2014
Cash flows from operating activities
Net income (loss)	$	(111,394	)	$	8,102
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	253,056			215,623
Impairments	1,084			123,992
Accretion of firm transportation obligation	705			991
Derivative contracts:
Net gains	(52,073		)	(8,130		)
Cash settlements, net	104,590			(17,836		)
Deferred income tax expense (benefit)	266			(339		)
Gain on sales of assets, net	(50,803		)	(120,295		)
Non-cash exploration expense	4,903			8,387
Non-cash interest expense	3,504			3,114
Share-based compensation (equity-classified)	3,369			2,638
Other, net	(17		)	325
Changes in operating assets and liabilities, net	5,051			(16,122		)
Net cash provided by operating activities	162,241			200,450
Cash flows from investing activities
Receipts to settle working capital adjustments assumed in acquisition, net	—			33,712
Capital expenditures – property and equipment	(324,876		)	(545,031		)
Proceeds from sales of assets, net	73,670			311,913
Net cash used in investing activities	(251,206		)	(199,406		)
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 revolving credit facility borrowings	203,000			377,000
Repayment of revolving credit facility borrowings	(98,000		)	(583,000		)
Debt issuance costs paid	(744		)	(151		)
Dividends paid on preferred stock	(18,201		)	(5,165		)
Other, net	—			1,414
Net cash provided by financing activities	86,055			99,172
Net (decrease) increase in cash and cash equivalents	(2,910		)	100,216
Cash and cash equivalents – beginning of period	6,252			23,474
Cash and cash equivalents – end of period	$	3,342		$	123,690
Supplemental disclosures:
Cash paid for:
Interest	$	47,489		$	47,778
Income taxes	$	7		$	100
Non-cash investing activities:
Changes in accrued liabilities related to capital expenditures	$	(41,800	)	$	12,805

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, 2015

(in thousands, except per share amounts)

1.  Organization

Penn Virginia Corporation (together with its consolidated subsidiaries unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have less significant operations in Oklahoma, primarily the Granite Wash.

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, 2014. Operating results for the nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheet or cash flows.

Going Concern Presumption and Management’s Plans

These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. We have incurred net losses in each of the three years ending December 31, 2014, and reported a net loss attributable to common shareholders of $(129.5) million for the nine months ended September 30, 2015. While we were in compliance with the covenants of our revolving credit agreement (the “Revolver”) as of September 30, 2015, based on our current operating forecast and capital structure, we do not believe we will be able to comply with all of the covenants under the Revolver during the next twelve months. We are also dependent on obtaining additional debt and/or equity financing to continue our planned principal business operations. These factors raise substantial doubt about our ability to continue as a going concern.

Management’s plans in regard to these matters consist principally of restructuring our debt or seeking additional debt or equity funding from outside sources. We are actively working to address these matters, however, there can be no assurance that our efforts will be successful. The Condensed Consolidated Financial Statements do not include any adjustments that may result from the outcome of this uncertainty.

Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering 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. Due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:

• We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period (see Note 12). We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.

• We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015 (see Note 3).

• We suspended the payment of dividends on our convertible preferred stock in September 2015 (see Note 13).

• We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015 (see Note 3).

• We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.

• We engaged Jefferies LLC (“Jefferies”) to advise us with respect to asset-level financing transactions and various financing and debt restructuring options (see Note 12).

7

While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior subordinated notes become due in April and May of 2016. Moreover, unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016.

Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection.

Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.

New Accounting Pronouncements

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015–03”) on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10) as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

In 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. In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, that defers by one year the effective date of ASU 2014–09 to fiscal years beginning after December 17, 2017, or calendar year 2018 for us. 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.

Subsequent Events

Management has evaluated all activities of the Company through the date upon which our Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of non-core properties in the southwestern portion of our Eagle Ford acreage referenced above and in Note 3, 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. Divestitures

East Texas and Other Properties

In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The carrying value of the net assets disposed in this transaction was $28.5 million, including oil and gas properties and other fixed assets of $32.3 million, net of related asset retirement obligations (“AROs”) of $3.8 million. The net pre-tax operating income (loss) attributable to the East Texas assets was $1.0 million and $(6.9) million for the three months ended September 30, 2015 and 2014 and $1.7 million and $(18.4) million for the nine months ended September 30, 2015 and 2014. The net proceeds from this transactions were used to pay down a portion of our outstanding borrowings under the Revolver.

In October 2015, we also sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for approximately $13 million, net of transaction costs and customary closing adjustments. We expect to recognize a loss of approximately $9 million on this transaction in the fourth quarter of 2015.

Oil Gathering System Construction Rights

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 approximately $147 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate transportation

8

services for a substantial portion of our 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 to be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be in the first quarter of 2016. In September 2015, the gathering agreement with Republic was amended to reduce the number of wells initially required to be connected to the pipeline system, provide for alternative transportation in areas that will not be served by the pipeline and also reduce the gathering fees. As a result of the amendment, we recognized $8.4 million of deferred gain in September 2015. As of September 30, 2015, $2.3 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $73.5 million, representing the remaining noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

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 (“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 $0.3 million of the deferred gain during each of the nine months ended September 30, 2015 and 2014. As of September 30, 2015, $0.4 million of the remaining deferred gain was included as a component of Accounts payable and accrued expenses and $9.5 million, representing the noncurrent portion, was 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,
	2015			2014
Customers	$	37,010		$	62,650
Joint interest partners	29,693			120,708
Other	7,872			6,549
	74,575			189,907
Less: Allowance for doubtful accounts	(1,555		)	(280		)
	$	73,020		$	189,627

For the nine months ended September 30, 2015, two customers accounted for $108.4 million, or approximately 50%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2015 were $62.3 million and $46.1 million, or 29% and 21% of the consolidated total, respectively. As of September 30, 2015, $16.5 million, or approximately 45% of our consolidated accounts receivable from customers, was related to these customers.

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, $55.7 million and $52.6 million, or approximately 21%, 18%, 13% and 13% of the consolidated total. As of December 31, 2014, $39.3 million, or approximately 63% 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. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We utilize collars and swaps, 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.

9

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.

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, 2015:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2015 1	Collars	3,000	$	86.67	$	94.73	$	6,817	$	—
Fourth quarter 2015 1	Swaps	8,000	$	91.06			26,603		—
First quarter 2016	Swaps	6,000	$	80.41			17,903		—
Second quarter 2016	Swaps	6,000	$	80.41			17,154		—
Third quarter 2016	Swaps	6,000	$	80.41			16,764		—
Fourth quarter 2016	Swaps	6,000	$	80.41			16,150		—
Settlements to be received in subsequent period							10,970		—

_______________________

¹ Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015.

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,
	2015		2014			2015			2014
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	32,258	$	(7,557	)	$	104,590		$	(17,836	)
Gains (losses) attributable to:
Commodity contracts	12,443		74,014			(52,517		)	25,966
	$	44,701	$	66,457		$	52,073		$	8,130

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, 2015				December 31, 2014
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	96,211	$	—	$	128,981	$	—
Commodity contracts	Derivative assets/liabilities – noncurrent	16,149		—		35,897		—
		$	112,360	$	—	$	164,878	$	—

10

As of September 30, 2015, we reported a commodity derivative asset of $112.4 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with four 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.

6. Property and Equipment

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

	As of
	September 30,			December 31,
	2015			2014
Oil and gas properties:
Proved	$	2,687,598		$	3,390,482
Unproved	125,571			125,676
Total oil and gas properties	2,813,169			3,516,158
Other property and equipment	31,423			75,073
Total properties and equipment	2,844,592			3,591,231
Accumulated depreciation, depletion and amortization	(1,026,006		)	(1,766,133		)
	$	1,818,586		$	1,825,098

7. Long-Term Debt

The following table summarizes our long-term debt as of the dates presented giving effect to the adoption of ASU 2015–03:

	As of
	September 30, 2015				December 31, 2014
	Principal		Unamortized Issuance Costs		Principal		Unamortized Issuance Costs
Revolving credit facility 1	$	140,000			$	35,000
Senior notes due 2019	300,000		$	3,510	300,000		$	4,131
Senior notes due 2020	775,000		18,128		775,000		20,440
Totals	1,215,000		$	21,638	1,110,000		$	24,571
Long-term debt, net of unamortized issuance costs	$	1,193,362			$	1,085,429

_______________________

¹ Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, are presented as a component of Other assets (see Note 10) in accordance with ASU 2015-15.

Revolving Credit Facility

Subsequent to the sale of our East Texas assets in August 2015, the commitment and borrowing base under the Revolver were reduced to $395 million from $425 million. In addition to the outstanding borrowings, we had letters of credit of $1.8 million outstanding as of September 30, 2015. As of September 30, 2015, our available borrowing capacity under the Revolver was $253.2 million.

In November 2015 in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program. The Revolver 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. The next semi-annual redetermination is scheduled for May 2016. Revolver borrowings may be used for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.

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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, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 2.0000%, which is derived from an Adjusted LIBOR rate of 0.2500% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2015, 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.

In order to borrow under the Revolver, we must make certain representations and warranties to our bank lenders at the time of each borrowing, including a representation relating to our solvency. If we are unable to make these representations and warranties, we would be unable to borrow under the Revolver, absent a waiver. We will not be able to give the solvency representation if at the time we desire to make a future borrowing we are unable to determine that the fair market value of our assets exceeds the face amount of our liabilities.

The Revolver includes current ratio, leverage ratio and credit exposure financial covenants. Under the current ratio covenant, the ratio of current assets to current liabilities as of the last day of any fiscal quarter may not be less than 1.0 to 1.0. 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. Under the leverage ratio covenant, the ratio of total debt to EBITDAX, for any four consecutive quarters may not exceed 4.75 to 1.0 through March 31, 2016; 5.25 to 1.0 through June 30, 2016; 5.50 to 1.0 through December 31, 2016; 4.50 to 1.0 through March 31, 2017; and 4.0 to 1.0 through maturity in September 2017. Furthermore, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if the leverage ratio for the preceding four quarters exceeds 5.0 to 1.0. Under the credit exposure covenant, the ratio of credit exposure to EBITDAX, for any four consecutive quarters ending on or prior to March 31, 2017 may not exceed 2.75 to 1.0. Credit exposure consists of all outstanding borrowings under the Revolver, including any outstanding letters of credit.

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% which is payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in April 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 8.50% 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.50% which is payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. 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.

Guarantees

The guarantees 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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8. Income Taxes

We recognized a federal income tax benefit for the three and nine months ended September 30, 2015 at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of recent cumulative losses. The income tax provision includes a benefit of $0.7 million attributable to a federal return to provision adjustment and a minimal deferred state income tax expense of $0.3 million resulting in a combined effective tax rate of 0.4% for the nine months ended September 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.4% is due primarily to the valuation allowance placed against our deferred tax assets.

We recognized an income tax benefit for nine months ended September 30, 2014 at an effective rate of 4.4% which reflects the adverse effects of losses incurred in jurisdictions for which we may not realize a tax benefit and therefore recorded a valuation allowance against the related deferred tax assets.

We paid state income taxes of less than $0.1 million during the nine months ended September 30, 2015 and $0.1 million during the nine months ended September 30, 2014. In October 2015, we received a federal income tax refund of $0.7 million which, as of September 30, 2015, is included as a component of Other current assets on our Condensed Consolidated Balance Sheets.

9. Firm Transportation Obligation

We have a contractual obligation 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 following table reconciles the obligation as of the dates presented:

	As of
	September 30,			December 31,
	2015			2014
Balance at beginning of period	$	14,790		$	15,993
Accretion	705			1,301
Cash payments, net	(1,691		)	(2,504		)
Balance at end of period	$	13,804		$	14,790

The accretion of the obligation, net of any recoveries from periodic sales of our contractual capacity, is charged as an offset to Other revenue. As of September 30, 2015, $2.8 million of the obligation is classified as current and is included in the Accounts payable and accrued liabilities caption while the remaining $11.0 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.

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10. 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,
	2015		2014
Other current assets:
Tubular inventory and well materials	$	2,925	$	5,802
Prepaid expenses	3,614		4,215
Other	763		97
	$	7,302	$	10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	$	4,014	$	4,123
Deferred issuance costs of the Revolver	1,796		1,623
Other	26		95
	$	5,836	$	5,841
Accounts payable and accrued liabilities:
Trade accounts payable	$	24,768	$	122,994
Drilling and other lease operating costs	26,643		68,842
Royalties and revenue – related	52,062		78,359
Compensation – related	12,853		9,197
Interest	37,438		15,555
Preferred stock dividends	—		6,067
Other	8,144		11,213
	$	161,908	$	312,227
Other liabilities:
Deferred gains on sales of assets	$	82,944	$	90,569
Firm transportation obligation	11,068		12,042
Asset retirement obligations	2,570		5,889
Defined benefit pension obligations	1,508		1,753
Postretirement health care benefit obligations	965		890
Compensation – related	1,150		7,631
Deferred compensation – SERP obligations and other	4,020		4,183
Other	1,012		929
	$	105,237	$	123,886

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11. 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, 2015, 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, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	68,272	$	300,000	$	234,000	$	300,000
Senior Notes due 2020	197,675		775,000		620,000		775,000
	$	265,947	$	1,075,000	$	854,000	$	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, 2015
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:
Commodity derivative assets – current	$	96,211	$	—	$	96,211	$	—
Commodity derivative assets – noncurrent	16,149		—		16,149		—
Assets of SERP	4,014		4,014		—		—
Liabilities:
Deferred compensation – SERP obligations	4,019		4,019		—		—

	As of December 31, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	128,981		$	—		$	128,981	$	—
Commodity derivative assets – noncurrent	35,897			—			35,897		—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,178		)	(4,178		)	—		—

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, 2015 and 2014.

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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 asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes of recognizing and measuring asset impairments include, but are not limited to, estimates of proved and probable reserves, future commodity prices, 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.

12. Commitments and Contingencies

Drilling and Completion Commitments

As of September 30, 2015, we had a contractual commitment for one drilling rig with a term expiring in February 2016. The minimum commitment under this agreement is $2.4 million for the fourth quarter of 2015 and $0.8 million in 2016. In September 2015, we renegotiated an existing commitment to purchase certain coil tubing services at a lower rate and extended the expiration from December 31, 2015 to June 30, 2016. The minimum commitment remaining under this agreement is $1.0 million. The drilling rig and coil tubing services 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 the penalty is based on the number of days remaining in the contractual term. The penalty amount would have been $3.4 million had we terminated those agreements on September 30, 2015.

In 2015, we reduced our total drilling rig count from eight to one. We incurred a total of $6.2 million in early termination charges with respect to these terminations in the nine months ended September 30, 2015, which have been reported as a component of Exploration expense on our Condensed Consolidated Statements of Operations.

Firm Transportation Commitments

We have entered into contracts for firm transportation capacity rights for specified daily volumes on various pipeline systems with remaining terms that range from less than one to 13 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. The minimum commitment under these agreements is $0.5 million for the fourth quarter of 2015 and approximately $1.1 million per year through 2028. We may sell excess capacity to third parties at our discretion.

Gathering and Intermediate Transportation Commitments

We have a long-term agreement for 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 payments regardless of the volume of natural gas production for the first three years of the term. The minimum fee requirement remaining under this agreement is $1.1 million for the fourth quarter of 2015 and $5.0 million in 2016.

We also have long-term agreements for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our payment obligations with respect to these services will begin when construction of the gathering and transportation system is completed, which is expected to be in the first quarter of 2016. The agreements also 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 approximately $12.3 million on an annual basis.

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Financial Advisory Commitment

In July 2015, we retained Jefferies to provide financial advice generally and to act as our exclusive financial advisor in connection with asset-level financing transactions with investors related to our Eagle Ford assets, including joint venture arrangement transactions. In connection with this engagement, Jefferies is also advising us with respect to various financing and debt restructuring options. In addition to certain cash-based fees in connection with these services, we have agreed to pay Jefferies an advisory fee of 6.5 million shares of our common stock payable upon the closing of an asset-level financing transaction.

Other Commitments

In connection with our August 2014 acquisition of undeveloped acreage in the Eagle Ford in Lavaca County, Texas, we committed to providing a drilling carry in the amount of $10.7 million to support development of this acreage through July 2017. If we have not incurred the full balance of the drilling carry by the third anniversary date of the transaction, we will be required to make a cash payment to the seller to satisfy any shortfall.

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 that remained outstanding as of September 30, 2015. As of September 30, 2015, we also had AROs of approximately $2.6 million attributable to the plugging of abandoned wells.

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13. 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, 2015 and 2014:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2014			Net Loss			Offering		Declared 1			Changes 2			2015
Preferred stock 3	$	4,044		$	—		$	—	$	—		$	(87	)	$	3,957
Common stock 3	529			—			—		—			19			548
Paid-in capital 3	1,206,305			—			—		—			2,882			1,209,187
Accumulated deficit	(535,176		)	(111,394		)	—		(12,134		)	—			(658,704		)
Deferred compensation obligation	3,211			—			—		—			229			3,440
Accumulated other comprehensive income 4	249			—			—		—			(32		)	217
Treasury stock	(3,345		)	—			—		—			(229		)	(3,574		)
	$	675,817		$	(111,394	)	$	—	$	(12,134	)	$	2,782		$	555,071
	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

_______________________

¹ Includes dividends declared of $300.00 per share and $450.00 per share of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the nine months ended September 30, 2015 and 2014, respectively, and $300.00 per share and $198.33 per share of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the nine months ended September 30, 2015 and 2014, respectively.

² Includes equity-classified share-based compensation of $3,369 and $2,638 for the nine months ended September 30, 2015 and 2014, respectively.

³ A total of 875 shares, or 87,500 depositary shares, of the Series A Preferred Stock were converted into 1,458,336 shares of our common stock during the nine months ended September 30, 2015. 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 during the 2014 period.

⁴ 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, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(49) and $114 and are presented above net of taxes of $(17) and $40, respectively.

In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. While the accumulation does not result in presentation of a liability on the balance sheet, the accumulated dividends are deducted from our net income (or added to our net loss) in the determination of income (loss) attributable to common shareholders and the related earnings (loss) per share. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends, including $1.0 million attributable to dividends of $150.00 per share on 7,070 eligible shares of the Series A Preferred Stock and $4.9 million attributable to dividends of $150.00 per share on 32,500 eligible shares of the Series B Preferred Stock.

If we do not pay dividends on our Series A Preferred Stock and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of both series of preferred stock, voting together as a single class, will have the right to elect two additional directors to serve on our board of directors until all accumulated and unpaid dividends are paid in full.

In May 2015, Penn Virginia’s articles of incorporation were amended to increase the number of total authorized shares of common stock by 100 million to 228 million from 128 million.

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14. 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 the 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 the 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,
	2015			2014			2015			2014
Equity-classified awards:
Stock option awards	$	462		$	403		$	1,242		$	1,193
Common, deferred and restricted stock and stock unit awards	801			584			2,127			1,445
	1,263			987			3,369			2,638
Liability-classified awards	(851		)	(360		)	(686		)	6,632
	$	412		$	627		$	2,683		$	9,270

In February 2015, we paid $1.5 million in cash pursuant to the terms of PBRSU grants made in 2012.

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,
	2015			2014			2015			2014
Interest on borrowings and related fees	$	23,239		$	22,559		$	69,371		$	69,477
Amortization of debt issuance costs	1,224			1,063			3,504			3,114
Capitalized interest	(1,478		)	(1,669		)	(4,854		)	(4,875		)
	$	22,985		$	21,953		$	68,021		$	67,716

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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,
	2015			2014			2015			2014
Net income (loss)	$	25,900		$	89,661		$	(111,394	)	$	8,102
Less: Preferred stock dividends	(5,935		)	(7,641		)	(18,069		)	(11,081		)
Less: Induced conversion of preferred stock	—			(888		)	—			(4,256		)
Net income (loss) attributable to common shareholders – basic	$	19,965		$	81,132		$	(129,463	)	$	(7,235	)
Add: Preferred stock dividends 1	5,935			7,641			—			—
Add: Induced conversion of preferred stock 1	—			888			—			—
Net income (loss) attributable to common shareholders – diluted	$	25,900		$	89,661		$	(129,463	)	$	(7,235	)
Weighted-average shares – basic	72,651			71,536			72,438			67,909
Effect of dilutive securities 2	30,801			32,070			—			—
Weighted-average shares – diluted	103,452			103,606			72,438			67,909

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015 and 2014, approximately 31.1 millionand24.9 million, respectively, of 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.

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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;

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

• compliance with debt covenants;

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

• our ability to continue to borrow under the Revolver;

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

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

• 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;

• 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 the ability of these parties to meet their future obligations;

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

• physical, electronic and cybersecurity breaches;

• 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, 2014 and Item 1A of Part II of this Quarterly Report on Form 10-Q.

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 us or persons acting on our 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 amounts for the 2014 periods have been reclassified to conform to the current year presentation. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables.

Overview and Executive Summary

We are an independent oil and gas company engaged in the onshore exploration, development and production of oil, NGLs and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have less significant operations in Oklahoma, primarily the Granite Wash. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 million barrels of oil equivalent, or MMBOE, including approximately 15.8 MMBOE of proved reserves attributable to our recently divested East Texas assets in August 2015 and certain non-core properties in South Texas that were sold in October 2015.

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,
	2015			2014			2015			2014
Total production (MBOE)	1,930			2,089			6,295			5,973
Average daily production (BOEPD)	20,976			22,706			23,058			21,881
Crude oil and NGL production (MBbl)	1,537			1,555			4,934			4,238
Crude oil and NGL production as a percent of total	80		%	74		%	78		%	71		%
Product revenues, as reported	$	60,690		$	141,860		$	216,948		$	411,441
Product revenues, as adjusted for derivatives	$	92,948		$	134,303		$	321,538		$	393,605
Crude oil and NGL revenues as a percent of total, as reported	90		%	91		%	90		%	88		%
Realized prices:
Crude oil ($/Bbl)	$	42.42		$	95.19		$	47.35		$	97.72
NGL ($/Bbl)	$	9.81		$	31.76		$	12.45		$	34.18
Natural gas ($/Mcf)	$	2.68		$	4.17		$	2.71		$	4.60
Aggregate ($/BOE)	$	31.45		$	67.91		$	34.46		$	68.88
Operating costs ($/BOE):
Lease operating	$	5.86		$	7.07		$	5.37		$	6.17
Gathering, processing and transportation	2.93			2.60			3.10			2.11
Production and ad valorem taxes	1.80			3.68			2.09			3.77
General and administrative 1	4.67			5.22			4.79			5.66
Total operating costs	$	15.26		$	18.57		$	15.35		$	17.71
Depreciation, depletion and amortization ($/BOE)	$	39.82		$	34.47		$	40.20		$	36.10
Cash provided by operating activities	$	63,960		$	101,257		$	162,241		$	200,450
Cash paid for capital expenditures	$	60,883		$	194,451		$	324,876		$	545,031
Cash and cash equivalents at end of period							$	3,342		$	123,690
Debt outstanding at end of period							$	1,215,000		$	1,075,000
Credit available under revolving credit facility at end of period 2							$	253,196		$	453,846
Net development wells drilled and completed	6.5			15.4			34.1			44.2

_______________________

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.65 and $0.47 for the three months ended September 30, 2015 and 2014 and $0.54 and $0.44 for the nine months ended September 30, 2015 and 2014 and liability-classified share-based compensation of $(0.44) and $(0.17) for the three months ended September 30, 2015 and 2014 and $(0.11) and $1.11 for the nine months ended September 30, 2015 and 2014.

² Based on the commitment and borrowing base of $395 million as of September 30, 2015 less outstanding borrowings and letters of credit.

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As discussed in greater detail in the “Key Developments” and “Financial Condition” sections that follow, due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:

• We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period. We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.

• We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015.

• We suspended the payment of dividends on our convertible preferred stock in September 2015.

• We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015.

• We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.

• We engaged Jefferies LLC, or Jefferies, to advise us with respect to asset-level financing transactions and various financing and debt restructuring options.

To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The “Financial Condition – Capital Resources” 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, 2015 and 2014.

In the three months ended September 30, 2015, our crude oil and NGL production increased to 80 percent from 74 percent of our total production compared to the three month period ended September 30, 2014. Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. As of November 6, 2015, we operated approximately 300 producing Eagle Ford wells and had working interests in an additional 36 non-operated producing Eagle Ford wells. Through this date, we have accumulated approximately 100,000 net acres in the Eagle Ford. We are currently operating one drilling rig in the Eagle Ford. Our 2015 capital program, which is exclusively dedicated to this play, is being financed with a combination of cash from operating activities, proceeds from the sale of non-core assets and borrowings under the Revolver.

Key Developments

The following general business developments and corporate actions had or may have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) decreases to the commitment and borrowing base under the Revolver, (ii) ongoing efforts to refinance the Company and improve liquidity, (iii) depressed commodity prices and our hedging program, (iv) the suspension of dividends on our our Series A 6% Convertible Perpetual Preferred Stock, or Series A Preferred Stock, and our Series B 6% Convertible Perpetual Preferred Stock, or Series B Preferred Stock, (v) production, development and capital expenditures in the Eagle Ford and (vi) the sale of our East Texas and other assets.

Revolver Commitment and Borrowing Base Reduction

In November 2015 in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program (see Note 7 to the Condensed Consolidated Financial Statements and the “Financial Condition” discussion that follows).

Ongoing Efforts to Refinance the Company

In July 2015, we retained Jefferies to provide financial advice generally and to act as our exclusive financial advisor in connection with asset-level financing transactions with investors related to our Eagle Ford assets, including joint venture arrangement transactions. In connection with this engagement, Jefferies is advising us with respect to various financing and debt restructuring options. In addition to certain cash-based fees in connection with these services, we have agreed to pay Jefferies an advisory fee of 6.5 million shares of our common stock payable upon the closing of an asset-level financing transaction.

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Depressed Commodity Prices and Our Hedging Program

Commodity prices continued to be volatile and depressed during the first three quarters of 2015. Our crude oil derivatives supported our liquidity by providing cash settlements of $32.3 million and $103.9 million during the three and nine months ended September 30, 2015. We have hedged approximately 11,000 barrels of oil per day, or BOPD, or approximately 95 percent of our expected crude oil production for the remainder of 2015, at a weighted-average floor/swap price of $89.86 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the remainder of 2015. No volumes are subject to the put options in 2016. For 2016, we have hedged a total of approximately 6,000 BOPD at a weighted-average swap price of $80.41 per barrel. We expect to remain unhedged with respect to natural gas production for the foreseeable future.

Suspension of Preferred Stock Dividends

In September 2015, we announced a suspension of quarterly dividends on our outstanding Series A and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends. We will re-evaluate the dividend payment policy on a quarterly basis.

The suspension of quarterly dividends does not affect our business operations and does not cause an event of default under any of our debt agreements.

If we do not pay dividends on our Series A and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of both series of preferred stock, voting together as a single class, will have the right to elect two additional directors to serve on our board of directors until all accumulated and unpaid dividends are paid in full.

Production, Development and Capital Expenditures in the Eagle Ford

Our Eagle Ford production was 18,528 BOEPD during the three months ended September 30, 2015 with oil comprising 12,826 BOPD, or 69 percent, and NGLs and natural gas comprising approximately 17 percent and 14 percent. Our third quarter production represented a nine percent decrease compared to 20,259 BOEPD during the three months ended June 30, 2015, of which 13,750 BOPD, or 68 percent, was crude oil, 17 percent was NGLs and 15 percent was natural gas. The sequential decline in production was attributable primarily to our reduction in drilling activity as the year progressed in light of lower oil and gas prices.

During the three months ended September 30, 2015, we drilled and completed nine gross (6.5 net) wells in the Eagle Ford for a total of 55 gross (34.1 net) wells on a year-to-date basis. The average drilling and completion costs for 11 gross (two-string) wells turned in line during the three months ended September 30, 2015 was approximately $5.7 million, or 30 percent lower from an average of $8.2 million for 16 gross (two-string and three-string wells) wells turned in line in the three months ended June 30, 2015. The decrease in average drilling and completion cost was driven by a transition to drilling exclusively two-string wells, whereas only three of the second quarter wells were two-string wells. In addition, seven of the third quarter wells were slickwater stimulated and all of the third quarter wells were fractured with approximately 46 percent more proppant per stage, on average, than second quarter wells.

During the three months ended September 30, 2015, we have turned in line 11 gross (8.5 net) operated wells. As a group, these 11 wells had an average IP rate of 1,501 BOEPD over an average of 21.2 frac stages, with 93 percent of production from crude oil, compared to 798 BOEPD over an average of 24.4 frac stages for 16 wells in the three months ended June 30, 2015. All of the third quarter wells were drilled in the Lower Eagle Ford and had a 30-day average rate of 790 BOEPD, with 92 percent of production from crude oil, compared to an average of 497 BOEPD for the second quarter wells. The average amount of proppant per stage for these 11 wells was approximately 422,000 pounds and the average amount of proppant per lateral foot was approximately 1,800 pounds, compared to approximately 290,000 pounds per stage and 1,170 pounds per lateral foot in the three months ended June 30, 2015. We believe the strong improvement in early-time production rates is attributable to the use of slickwater stimulations, continued use of “zipper fracs” for alternating laterals on multi-well pads and increased frac intensity as measured by the increased proppant pumped per stage.

We anticipate total capital expenditures in 2015 of up to approximately $324 million including up to approximately $43 million during the fourth quarter of 2015. Preliminarily, we estimate 2016 capital expenditures to be up to approximately $160 million. For the remainder of 2015 and for 2016, due primarily to anticipated low oil prices, we will continue to focus our efforts on drilling, using one rig, less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where our economics are optimized.

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Sale of East Texas and Other Assets

In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The properties sold had net production of 1,898 BOEPD during the second quarter of 2015, consisting of 74 percent natural gas, 19 percent NGLs and seven percent crude oil. As a result of the divestiture, reported 2015 production is expected to decrease by an estimated 200 MBOE. Estimated proved reserves associated with the properties as of December 31, 2014 were 13.7 MMBOE, 85 percent of which were proved developed. The reserves consisted of 77 percent natural gas, 16 percent NGLs and six percent crude oil. The net proceeds from this transactions were used to pay down a portion of our outstanding borrowings under the Revolver.

In October 2015, we also sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for approximately $13 million, net of transaction costs and customary closing adjustments. We expect to recognize a loss of approximately $9 million on this transaction in the fourth quarter of 2015.

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Financial Condition

Liquidity

Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering 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.

During 2015, our capital expenditures will exceed our projected cash from operating activities; however, we have no debt maturities until September 2017 when the Revolver matures. We expect that we will be able to fund our capital expenditures as well as meet our debt service requirements and meet our working capital requirements for the remainder of 2015 with cash from operating activities, borrowings under the Revolver and proceeds from the sale of non-core assets.

In November 2015, in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver from $395 million to $275 million. Based on our current borrowings of$170 million and outstanding letters of credit of $1.8 million, we have only $103.2 million of borrowing capacity available under the Revolver as of November 6, 2015. While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior notes become due in April and May of 2016. Unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016. Moreover, the borrowing base under the Revolver may be further reduced in connection with the next semi-annual redetermination in May 2016. Such a further reduction could prevent us from borrowing additional amounts under the Revolver or, if the borrowing base were to be reduced below the then-outstanding borrowings, could require us to repay the shortfall.

Using prices through September 30, 2015, we estimate that our proved reserve volumes and the present value (discounted at 10% per annum) of estimated future net revenues of our proved oil and gas reserves, or PV10, has declined from the year-end 2014 estimates due primarily to the continued decline in commodity prices and reductions in our projected development plans, partially offset by lower estimated drilling costs and other direct expenses. We estimate that our proved reserves were 68.6 MMBOE and our PV10 was approximately $614 million as of September 30, 2015 as compared to 114.8 MMBOE and $1,472 million as of December 31, 2014, respectively. The decline in our PV10 could lead to further reductions in the borrowing base under the Revolver and could otherwise limit our ability to obtain alternative financing. Our cash flows, operating results, future growth prospects and financial condition, as well as our proved reserves volumes and PV10, could continue to be negatively impacted if the currently depressed crude oil and natural gas prices persist or deteriorate further.

Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection. Collectively, the factors discussed above raise substantial doubt about our ability to continue as a going concern.

Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing, and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.

Capital Resources

In 2015, we anticipate making capital expenditures of up to approximately $324 million in the aggregate including up to $43 million in the fourth quarter. We expect to allocate substantially all of our capital expenditures to the Eagle Ford. This includes approximately 93 percent for drilling and completions, five percent for leasehold acquisition and two percent for facilities and other projects. Our business plan for the remainder of 2015 assumes a drilling program utilizing one operated drilling rig. We continually review our drilling and capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, product pricing, 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.

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Cash From Operating Activities. 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 component 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 and swap 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, 2015, our commodity derivatives portfolio resulted in $103.9 million and $0.7 million of net cash receipts related to lower than anticipated prices received for our crude oil and natural gas production, respectively. If commodity prices remain depressed, we anticipate that our derivative portfolio will continue to result in receipts from settlements during the fourth quarter of 2015.

We have hedged approximately 11,000 BOPD, or approximately 95 percent of our expected crude oil production during the remainder of 2015, at a weighted-average floor/swap price of $89.86 per barrel. For 2016, we have hedged approximately 6,000 BOPD at weighted-average swap price of $80.41 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015. Our natural gas hedges have expired and we anticipate remaining unhedged with respect to natural gas production for the remainder of 2015.

Revolver Borrowings. The Revolver provides for a revolving commitment and borrowing base which is currently $275 million. The Revolver 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. The next semi-annual redetermination is scheduled for May 2016. Revolver borrowings may be used for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.

Subsequent to the sale of our East Texas assets in August 2015, the commitment and borrowing base under the Revolver were reduced to $395 million from $425 million. In addition to the outstanding borrowings, we had letters of credit of $1.8 million outstanding as of September 30, 2015. As of September 30, 2015, our available borrowing capacity under the Revolver was $253.2 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, 2015	$	191,065	$	218,000	2.2325	%
Nine months ended September 30, 2015	$	178,407	$	232,000	2.1036	%

In order to borrow under the Revolver, we must make certain representations and warranties to our bank lenders at the time of each borrowing, including a representation relating to our solvency. If we are unable to make these representations and warranties, we would be unable to borrow under the Revolver, absent a waiver. We will not be able to give the solvency representation if at the time we desire to make a future borrowing we are unable to determine that the fair market value of our assets exceeds the face amount of our liabilities. The current commodity environment creates substantial uncertainty as to our ability to continue to give the required representation regarding solvency. If we are unable to give the required representation, then we will need a waiver from our bank lenders in order to continue to be able to borrow under the Revolver. Although we believe our bank lenders’ loans are well secured under the terms of the Revolver, there is no assurance that the bank lenders will waive the requirement to give all representations and warranties.

Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-core 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.

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Cash Flows

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

	Nine Months Ended
	September 30,
	2015			2014			Variance
Cash flows from operating activities
Operating cash flows, net	$	125,248		$	300,644		$	(175,396	)
Working capital changes (excluding interest, income taxes and restructuring costs paid), net	(14,797		)	(35,740		)	20,943
Commodity derivative settlements received (paid), net:
Crude oil	103,909			(15,987		)	119,896
Natural gas	681			(1,849		)	2,530
Interest payments, net of amounts capitalized	(42,635		)	(42,903		)	268
Income taxes paid	(7		)	(100		)	93
Drilling rig termination charges paid	(6,416		)	—			(6,416		)
Strategic and financial advisory costs paid	(1,195		)	—			(1,195		)
ERP system development costs paid	—			(1,045		)	1,045
Acquisition arbitration and other costs paid	—			(589		)	589
Restructuring and exit costs paid	(2,547		)	(1,981		)	(566		)
Net cash provided by operating activities	162,241			200,450			(38,209		)
Cash flows from investing activities
Receipts to settle working capital adjustments assumed in acquisition, net	—			33,712			(33,712		)
Capital expenditures – property and equipment	(324,876		)	(545,031		)	220,155
Proceeds from sales of assets, net	73,670			311,913			(238,243		)
Net cash used in investing activities	(251,206		)	(199,406		)	(51,800		)
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 (repayments) from revolving credit facility borrowings, net	105,000			(206,000		)	311,000
Debt issuance costs paid	(744		)	(151		)	(593		)
Dividends paid on preferred stock	(18,201		)	(5,165		)	(13,036		)
Other, net	—			1,414			(1,414		)
Net cash provided by financing activities	86,055			99,172			(13,117		)
Net (decrease) increase in cash and cash equivalents	$	(2,910	)	$	100,216		$	(103,126	)

Cash Flows From Operating Activities. Despite higher total production volume during the nine months ended September 30, 2015 compared to the corresponding period in 2014, commodity prices declined substantially resulting in lower realized cash receipts from product sales. During the 2015 period, we paid early termination charges for the release of four drilling rigs, of which $0.7 million was accrued at the end of 2014. During the 2015 period, we also incurred and paid professional fees and other consulting costs associated with our ongoing initiatives with respect to corporate strategy, including the search for a new chief executive officer, and refinancing the Company. Restructuring and exit costs were higher during the 2015 period due primarily to the payment of termination and severance benefits of $0.8 million in connection with ongoing efforts to reduce our our administrative cost structure. The overall decline in operating cash flows was partially offset by a combination of (i) cash settlements from our commodity derivatives portfolio which generated cash receipts during the 2015 period as compared to net payments during the 2014 period, (ii) lower working capital changes driven by the timing of net collections from joint venture partners during the 2015 period as our capital program contracted as compared to the 2014 period when the capital program was expanding and (iii) non-recurring payments for ERP system development costs and acquisition-related arbitration and other costs paid in the 2014 period.

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Cash Flows From Investing Activities. Cash paid for capital expenditures was substantially lower during the nine months ended September 30, 2015 compared to the corresponding period during 2014 due primarily to the reduction in our capital program including reductions in the number of operating drilling rigs and well completion and frac crews. Our capital expenditures during the 2015 period were partially offset by the receipt of net proceeds from the sale of our East Texas assets. Capital expenditures during the 2014 period were partially offset by the receipt of net proceeds from the sale of our natural gas gathering and gas lift assets in South Texas in January 2014, the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas in July 2014, the sale of our Selma Chalk assets in Mississippi in July 2014 and proceeds from the resolution of arbitration matters in connection with a 2013 acquisition.

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

	Nine Months Ended
	September 30,
	2015		2014
Oil and gas:
Drilling and completion	$	262,130	$	438,150
Lease acquisitions and other land-related costs 1	13,587		99,917
Pipeline, gathering facilities and other equipment	3,634		11,811
Geological, geophysical (seismic) and delay rental costs	836		5,608
	280,187		555,486
Other – Corporate	526		1,287
Total capital program costs	$	280,713	$	556,773

______________________

¹ Includes site preparation and other pre-drilling costs.

The following table reconciles the total costs of our capital 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,
	2015			2014
Total capital program costs	$	280,713		$	556,773
Decrease (increase) in accrued capitalized costs	41,800			(12,805		)
Less:
Exploration costs charged to operations:
Geological, geophysical (seismic) and delay rental costs	(836		)	(5,608		)
Transfers from tubular inventory and well materials	(4,154		)	(35		)
Add:
Tubular inventory and well materials purchased in advance of drilling	2,499			1,831
Capitalized interest	4,854			4,875
Total cash paid for capital expenditures	$	324,876		$	545,031

Cash Flows From Financing Activities. Cash flows from financing activities for the nine months ended September 30, 2015 included net borrowings of $105 million under the Revolver used to fund a portion of our capital expenditures while the 2014 period included net repayments of $206 million sourced primarily by the offering of our Series B Preferred Stock, the net proceeds from the sale of our South Texas natural gas gathering and gas lift assets, the sale of rights to construct a crude oil gathering and intermediate transportation system in South Texas and the sale of our Selma Chalk assets in Mississippi. We paid total dividends of $18.2 million for the Series A Preferred Stock and Series B Preferred Stock during the nine months ended September 30, 2015. Dividends of $5.2 million were paid during the comparable period in 2014 on the Series A Preferred Stock as well as $4.3 million of payments to induce the conversion of approximately 30 percent of the outstanding shares of the Series A Preferred Stock. We paid issuance costs associated with amendments to the Revolver during both the 2015 and 2014 periods including $0.7 million in the 2015 period and $0.2 million in the 2014 period. We also received proceeds of $1.4 million during the 2014 period from the exercise of stock options.

29

Capitalization

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

	September 30,			December 31,
	2015			2014
Revolving credit facility	$	140,000		$	35,000
Senior notes due 2019	300,000			300,000
Senior notes due 2020	775,000			775,000
Total debt	1,215,000			1,110,000
Shareholders’ equity 1	555,071			675,817
	$	1,770,071		$	1,785,817
Debt as a % of total capitalization	69		%	62		%

_____________________

¹ Includes 7,070 and 7,945 shares of the Series A Preferred Stock as of September 30, 2015 and December 31, 2014, respectively, and 32,500 shares of the Series B Preferred Stock as of September 30, 2015 and December 31, 2014. Both series of preferred stock have a liquidation preference of $10,000 per share representing a total of $395.7 million and $404.4 million as of September 30, 2015 and December 31, 2014, 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, 2015, the actual interest rate applicable to the Revolver was 2.0000%, which is derived from an Adjusted LIBOR rate of 0.2500% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2015, 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% which is payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2020 Senior Notes. The 8.50% Senior Notes due 2020, or the 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.50% which is payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. 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 and Series B Preferred Stock. The annual dividend on each share of the Series A Preferred Stock and 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; however, the utilization of common stock to pay dividends on the Series B Preferred Stock would require shareholder approval. In addition, cash payment of dividends may be limited by certain financial covenants under the Revolver (see Covenant Compliance that follows).

Each share of the Series A Preferred Stock and 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 prices, which is initially $6.00 per share for the Series A Preferred Stock and $18.34 per share for the Series B Preferred Stock and both series are 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 and 545.17 shares of our common stock for each share of the Series B Preferred Stock. The Series A Preferred Stock and Series B Preferred Stock are not redeemable for cash by us or the holders at any time. At any time on or after October 15, 2017 in the case of the Series A Preferred Stock and July 15, 2019 in the case of the Series B Preferred Stock, we may, at our option, cause all outstanding shares of the Series A Preferred Stock and Series B Preferred Stock, respectively, to be automatically converted into shares of our common stock at the then-applicable conversion prices for

30

each series if the closing sale price of our common stock exceeds 130% of the then-applicable conversion prices for a specified period prior to conversion. If a holder elects to convert shares of the Series A Preferred Stock and 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.

In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. While the accumulation does not result in presentation of a liability on the balance sheet, the accumulated dividends are deducted from our net income (or added to our net loss) in the determination of income (loss) attributable to common shareholders and the related earnings (loss) per share. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends, including $1.0 million attributable to dividends of $150.00 per share on 7,070 eligible shares of the Series A Preferred Stock and $4.9 million attributable to dividends of $150.00 per share on 32,500 eligible shares of the Series B Preferred Stock.

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.

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 4.75 to 1.0 for periods through March 31, 2016, 5.25 to 1.0 for periods through June 30, 2016, 5.50 to 1.0 for periods through December 31, 2016, 4.50 to 1.0 for periods through March 31, 2017 and 4.0 to 1.0 through maturity in September 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.

• Credit exposure to EBITDAX for any four consecutive quarters may not exceed 2.75 to 1.0 for periods ending after March 31, 2015 through March 31, 2017. Credit exposure consists of all outstanding borrowing under the Revolver plus any outstanding letters of credits.

• 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 the ratio of 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.

In addition, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if the total debt to EBITDAX ratio exceeds 5.0 to 1.0.

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, 2015 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, 2015:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.75 to 1	3.9 to 1
Credit exposure to EBITDAX	< 2.75 to 1	0.5 to 1
Current ratio	> 1.00 to 1	2.1 to 1
Interest coverage	> 2.25 to 1	2.8 to 1

Please read “Financial Condition – Liquidity” regarding potential future covenant compliance issues.

31

Results of Operations

Production

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

	Total Production				Average Daily Production
	Three Months Ended				Three Months Ended
	September 30,		2015 vs.		September 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(Total volume)				(Volume per day)
Crude oil (MBbl and Bbl per day)	1,205	1,247	(42	)	13,098	13,557	(458	)
NGLs (MBbl and Bbl per day)	332	308	24		3,605	3,351	254
Natural gas (MMcf and MMcf per day)	2,358	3,201	(843	)	26	35	(9	)
Total (MBOE and BOE per day)	1,930	2,089	(159	)	20,976	22,706	(1,730	)
% Change							(8	)%
	Three Months Ended				Three Months Ended
	September 30,		2015 vs.		September 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBOE)				(BOE per day)
Texas
South Texas	1,705	1,557	147		18,528	16,929	1,599
East Texas 1	103	208	(105	)	1,119	2,257	(1,138	)
Mid-Continent	117	258	(141	)	1,271	2,802	(1,531	)
Other 2	5	66	(61	)	58	719	(661	)
	1,930	2,089	(159	)	20,976	22,706	(1,730	)
	Nine Months Ended				Nine Months Ended
	September 30,		2015 vs.		September 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(Total volume)				(Volume per day)
Crude oil (MBbl and Bbl per day)	3,822	3,442	380		14,000	12,609	1,391
NGLs (MBbl and Bbl per day)	1,112	796	316		4,074	2,915	1,159
Natural gas (MMcf and MMcf per day)	8,165	10,412	(2,247	)	30	38	(8	)
Total (MBOE and BOE per day)	6,295	5,973	322		23,058	21,881	1,177
% Change							5	%
	Nine Months Ended				Nine Months Ended
	September 30,		2015 vs.		September 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBOE)				(BOE per day)
Texas
South Texas	5,473	4,307	1,166		20,049	15,777	4,271
East Texas 1	449	643	(194	)	1,644	2,356	(711	)
Mid-Continent	356	593	(236	)	1,305	2,171	(866	)
Other 2	16	431	(414	)	60	1,577	(1,517	)
	6,295	5,973	321		23,058	21,881	1,177

_______________________

¹ Includes production through August 31, 2015, the closing date of East Texas asset sale.

²  Comprised of our three active Marcellus Shale wells in Pennsylvania and, for periods through July 2014, our divested Selma Chalk assets in Mississippi.

Total production decreased during the three months ended September 30, 2015 compared to the corresponding period of 2014 due primarily to natural production declines in our Mid-Continent region as well as the sale of our East Texas assets in August 2015. Total production increased during the nine months ended September 30, 2015 compared to the corresponding period of 2014 due primarily to the continued development of our Eagle Ford assets in South Texas. The increase was partially offset by the aforementioned natural production declines and asset sales impacting the three month periods. Approximately 80 percent and 78 percent of total production during the three and nine months ended September 30, 2015 was attributable to oil and NGLs. This represents an increase of approximately 16 percent over the prior year-to-date period. During the three and nine months ended September 30, 2015, our Eagle Ford production represented approximately 88 percent and 87 percent of our total production compared to approximately 75 percent and 72 percent from this play during the corresponding periods of 2014.

32

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:

	Three Months Ended							Three Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Unit of volume)
Crude oil (Total revenue and $ per barrel)	$	51,124	$	118,716	$	(67,592	)	$	42.42	$	95.19	$	(52.77	)
NGLs (Total revenue and $ per barrel)	3,254		9,790		(6,536		)	9.81		31.76		(21.95		)
Natural gas (Total revenue and $ per Mcf))	6,312		13,354		(7,042		)	2.68		4.17		(1.50		)
Total (Total revenue and $ per BOE)	$	60,690	$	141,860	$	(81,170	)	$	31.45	$	67.91	$	(36.46	)
% Change												(57		)%
	Three Months Ended							Three Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per BOE)
Texas
South Texas	$	56,412	$	122,676	$	(66,264	)	$	33.09	$	78.77	$	(45.68	)
East Texas	1,819		6,638		(4,819		)	17.67		31.97		(14.30		)
Mid-Continent	2,425		10,827		(8,402		)	20.75		42.01		(21.26		)
Other	34		1,719		(1,685		)	6.38		26.00		(19.62		)
	$	60,690	$	141,860	$	(81,170	)	$	31.45	$	67.91	$	(36.46	)
	Nine Months Ended							Nine Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Unit of volume)
Crude oil (Total revenue and $ per barrel)	$	180,964	$	336,382	$	(155,418	)	$	47.35	$	97.72	$	(50.37	)
NGLs (Total revenue and $ per barrel)	13,841		27,200		(13,359		)	12.45		34.18		(21.73		)
Natural gas (Total revenue and $ per Mcf))	22,143		47,859		(25,716		)	2.71		4.60		(1.88		)
Total (Total revenue and $ per BOE)	$	216,948	$	411,441	$	(194,493	)	$	34.46	$	68.88	$	(34.42	)
% Change												(47		)%
	Nine Months Ended							Nine Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per BOE)
Texas
South Texas	$	200,740	$	349,596	$	(148,856	)	$	36.68	$	81.16	$	(44.48	)
East Texas	8,160		22,609		(14,449		)	18.18		35.16		(16.98		)
Mid-Continent	7,902		26,820		(18,918		)	22.18		45.26		(23.08		)
Other	146		12,416		(12,270		)	8.92		28.83		(19.91		)
	$	216,948	$	411,441	$	(194,493	)	$	34.46	$	68.88	$	(34.41	)

The following table provides an analysis of the change in our revenues for the three and nine month periods ended September 30, 2015 compared to the corresponding periods in the prior year:

	Three Months Ended 2015 vs. 2014									Nine Months Ended 2015 vs. 2014
	Revenue Variance Due to									Revenue Variance Due to
	Volume			Price			Total			Volume			Price			Total
Crude oil	$	(4,002	)	$	(63,590	)	$	(67,592	)	$	37,099		$	(192,517	)	$	(155,418	)
NGL	743			(7,279		)	(6,536		)	10,810			(24,169		)	(13,359		)
Natural gas	(3,515		)	(3,527		)	(7,042		)	(10,330		)	(15,386		)	(25,716		)
	$	(6,774	)	$	(74,396	)	$	(81,170	)	$	37,579		$	(232,072	)	$	(194,493	)

33

Effects of Derivatives

In the three and nine months ended September 30, 2015, we received $32.3 million and $104.6 million, respectively, in cash settlements of oil and gas derivatives. In the three and nine months ended September 30, 2014, we paid cash settlements of oil and gas derivatives of $7.6 million and $17.8 million, respectively. 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								Nine Months Ended
	September 30,					2015 vs.			September 30,					2015 vs.
	2015		2014			2014			2015		2014			2014
						Favorable (unfavorable)								Favorable (unfavorable)
Crude oil revenues as reported	$	51,124	$	118,716		$	(67,592	)	$	180,964	$	336,382		$	(155,418	)
Derivative settlements, net	32,258		(7,622		)	39,880			103,909		(15,987		)	119,896
	$	83,382	$	111,094		$	(27,712	)	$	284,873	$	320,395		$	(35,522	)
Crude oil prices per Bbl, as reported	$	42.42	$	95.19		$	(52.77	)	$	47.35	$	97.72		$	(50.37	)
Derivative settlements per Bbl	26.77		(6.11		)	32.89			27.19		(4.64		)	31.84
	$	69.19	$	89.08		$	(19.88	)	$	74.54	$	93.08		$	(18.53	)
Natural gas revenues as reported	$	6,312	$	13,354		$	(7,042	)	$	22,143	$	47,859		$	(25,716	)
Derivative settlements, net	—		65			(65		)	681		(1,849		)	2,530
	$	6,312	$	13,419		$	(7,107	)	$	22,824	$	46,010		$	(23,186	)
Natural gas prices per Mcf, as reported	$	2.68	$	4.17		$	(1.50	)	$	2.71	$	4.60		$	(1.88	)
Derivative settlements per Mcf	—		0.02			(0.02		)	0.08		(0.18		)	0.26
	$	2.68	$	4.19		$	(1.52	)	$	2.79	$	4.42		$	(1.62	)

Gain (Loss) on Sales of Property and Equipment

The three and nine months ended September 30, 2015 include a gain of approximately $43 million on the sale of our East Texas assets. In connection with an amendment to our crude oil gathering agreement with Republic, which included a pricing concession, we recognized $8.4 million of a gain that was previously deferred and being recognized over the term of the underlying agreement. In the nine months ended September 30, 2014, we recorded a gain of $63.0 million in connection with sale of rights to construct a crude oil gathering and intermediate transportation system to Republic and a gain of $57.0 million on the sale of our South Texas natural gas gathering and gas lift assets.

Other Revenues

Other revenues, which includes gathering, transportation, compression, water supply and disposal fees that we charge to third parties, net of marketing and related expenses and accretion of our unused firm transportation obligation, decreased during the nine months ended September 30, 2015 from the corresponding period in 2014 due primarily to lower third party throughput and drilling activity.

Lease Operating Expenses

	Three Months Ended							Nine Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
					Favorable (unfavorable)							Favorable (unfavorable)
Lease operating	$	11,304	$	14,761	$	3,457		$	33,780	$	36,878	$	3,098
Per unit of production ($/BOE)	$	5.86	$	7.07	$	1.21		5.37		6.17		$	0.80
% Change per unit of production					17		%					13		%

Lease operating expense decreased during the three and nine months ended September 30, 2015 on an absolute basis basis compared to the corresponding periods of 2014 due primarily to the sale of our East Texas assets in August 2015 and our Mississippi assets in July 2014. Lease operating expenses also decreased on a per-unit basis during these periods due primarily to costs in our South Texas region being spread over higher production volumes as well as a combination of cost containment efforts and lower oilfield service cost rates from certain vendors.

34

Gathering, Processing and Transportation

	Three Months Ended							Nine Months Ended
	September 30,				2015 vs.			September 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
					Favorable (unfavorable)							Favorable (unfavorable)
Gathering, processing and transportation	$	5,654	$	5,428	$	(226	)	$	19,535	$	12,605	$	(6,930	)
Per unit of production ($/BOE)	$	2.93	$	2.60	$	(0.33	)	$	3.10	$	2.11	$	(0.99	)
% Change per unit of production					(13		)%					(47		)%

Gathering, processing and transportation charges increased during the three and nine months ended September 30, 2015 compared to the corresponding periods of 2014 due primarily to higher production volumes and higher gathering and common delivery point compression charges for natural gas and NGL production in the South Texas region. These charges were partially offset by the effect of lower natural gas and NGL production in our Mid-Continent region and, prior to the sale in August 2015, our East Texas region as well as lower natural gas production following the sale of our Mississippi assets in July 2014.

Production and Ad Valorem Taxes

	Three Months Ended									Nine Months Ended
	September 30,						2015 vs.			September 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	2,800		$	6,845		$	4,045		$	9,857		$	18,739		$	8,882
Ad valorem taxes	683			845			162			3,282			3,766			484
	$	3,483		$	7,690		$	4,207		$	13,139		$	22,505		$	9,366
Per unit production ($/BOE)	$	1.80		$	3.68		$	1.88		$	2.09		$	3.77		$	1.68
% Change per unit of production							51		%							45		%
Production/severance tax rate as a percent of product revenue	4.6		%	4.8		%				4.5		%	4.6		%

Production taxes decreased during the three and nine months ended September 30, 2015 compared to the corresponding periods of 2014 due primarily to the substantial year-over-year decline in commodity prices. Ad valorem taxes declined during the three and nine months ended September 30, 2015 primarily as a result of the sale of our Mississippi assets in July 2014, partially offset by the expansion of our operations in the South Texas region.

General and Administrative

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

	Three Months Ended									Nine Months Ended
	September 30,						2015 vs.			September 30,					2015 vs.
	2015			2014			2014			2015			2014		2014
							Favorable (unfavorable)								Favorable (unfavorable)
Recurring general and administrative expenses	$	8,248		$	10,580		$	2,332		$	28,221		$	32,125	$	3,904
Share-based compensation (liability-classified)	(851		)	(360		)	491			(686		)	6,632		7,318
Share-based compensation (equity-classified)	1,263			987			(276		)	3,369			2,638		(731		)
Significant non-recurring expenses:
Acquisition-related arbitration costs	—			2			2			—			589		589
ERP system development costs	—			301			301			—			1,045		1,045
Strategic and financial advisory costs	733			—			(733		)	1,195			—		(1,195		)
Restructuring expenses	23			17			(6		)	766			26		(740		)
Total general and administrative expenses	$	9,416		$	11,527		$	2,111		$	32,865		$	43,055	$	10,190
Per unit of production ($/BOE)	$	4.88		$	5.52		$	0.64		$	5.22		$	7.21	$	1.99
% Change per unit of production							12		%						28		%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	4.67		$	5.22		$	0.55		$	4.79		$	5.66	$	0.87
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	4.27		$	5.06		$	0.79		$	4.48		$	5.38	$	0.90

35

Our total general and administrative expenses decreased on both an absolute and per-unit basis during the three and nine months ended September 30, 2015 compared to the corresponding periods of 2014. Decreases in recurring general and administrative expenses were due primarily to lower payroll and benefits attributable to lower employee headcount, lower cash-based incentive compensation and lower travel and entertainment and other corporate support costs.

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 change in fair value of the outstanding PBRSU grants. Our common stock performance relative to a defined peer group was less favorable during the 2015 periods resulting in a reduction in liability-classified share-based compensation.

Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, increased during the three and nine months ended September 30, 2015 due primarily to a higher weighting of share-based awards over cash-based awards with respect to the total compensation program for our senior management.

During the three and nine months ended September 30, 2015, we incurred professional fees and other consulting costs associated with our ongoing initiatives with respect to corporate strategy, including the search for a new chief executive officer, and refinancing the Company. During the 2014 periods, we incurred costs (including legal and litigation support fees) attributable to arbitration proceedings associated with a 2013 acquisition. We also incurred certain costs in the 2014 periods not eligible for capitalization, including post-implementation support and training with respect to our ERP system. In connection with our ongoing efforts to adjust the scale of our administrative cost structure, we terminated 18 employees and paid termination and severance benefits of $0.8 million during the nine months ended September 30, 2015. Additional headcount reductions were initiated in October 2015 resulting in incremental payment of severance and termination benefits in the amount of $0.2 million.

Exploration

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

	Three Months Ended								Nine Months Ended
	September 30,					2015 vs.			September 30,				2015 vs.
	2015		2014			2014			2015		2014		2014
						Favorable (unfavorable)							Favorable (unfavorable)
Unproved leasehold amortization	$	898	$	1,808		$	910		$	4,903	$	8,387	$	3,484
Drilling rig termination charges	517		—			(517		)	6,182		—		(6,182		)
Geological and geophysical (seismic) costs	172		205			33			678		4,785		4,107
Other, primarily delay rentals	86		(27		)	(113		)	159		823		664
	$	1,673	$	1,986		$	313		$	11,922	$	13,995	$	2,073

We incurred early termination charges in connection with the release of three drilling rigs in the Eagle Ford in February, May and August 2015, respectively. These charges were partially offset by lower unproved leasehold amortization attributable to a declining leasehold asset base subject to amortization in the 2015 periods as compared to the 2014 periods. Seismic and delay rental costs declined in the three and nine months ended September 30, 2015 period compared to the corresponding 2014 periods due to a significant decrease in our capital program and limited exploration activity.

Depreciation, Depletion and Amortization (DD&A)

The following table sets forth total and per unit costs for DD&A as well as the nature of the variance for the periods presented:

	Three Months Ended								Nine Months Ended
	September 30,					2015 vs.			September 30,						2015 vs.
	2015		2014			2014			2015			2014			2014
						Favorable (unfavorable)									Favorable (unfavorable)
DD&A expense	$	76,850	$	71,999		$	(4,851	)	$	253,056		$	215,623		$	(37,433	)
DD&A rate ($/BOE)	$	39.82	$	34.47		$	(5.35	)	$	40.20		$	36.10		$	(4.10	)
	Production		Rates			Total			Production			Rates			Total
DD&A variance due to:	$	5,480	$	(10,331	)	$	(4,851	)	$	(11,624	)	$	(25,809	)	$	(37,433	)

The effects of higher production volumes and higher depletion rates attributable to the higher-cost 2014 oil drilling program in the Eagle Ford were the primary factors attributable to the increase in DD&A during the nine months ended September 30, 2015. Lower production volume during the three months ended September 30, 2015 as compared to the corresponding period during 2014 partially mitigated the impact of higher depletion rates.

36

Impairments

We recorded an impairment charge of $1.1 million attributable to surplus tubular inventory and well materials during the nine months ended September 30, 2015. In September 2014, we recognized an oil and gas impairment of $6.1 million in connection with an exploration prospect drilled in the Mid-Continent region. In June 2014, we recorded an impairment charge of $117.9 million to write down the value of our Selma Chalk assets in Mississippi to their fair value in advance of their sale in July 2014.

Interest Expense

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

	Three Months Ended									Nine Months Ended
	September 30,						2015 vs.			September 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
Interest on borrowings and related fees	$	23,239		$	22,559		$	(680	)	$	69,371		$	69,477		$	106
Amortization of debt issuance costs	1,224			1,063			(161		)	3,504			3,114			(390		)
Capitalized interest	(1,478		)	(1,669		)	(191		)	(4,854		)	(4,875		)	(21		)
	$	22,985		$	21,953		$	(1,032	)	$	68,021		$	67,716		$	(305	)
Weighted-average debt outstanding	$	1,270,804		$	1,122,154					$	1,246,204		$	1,242,354
Weighted average interest rate	7.31		%	8.04		%				7.42		%	7.46		%

Interest expense increased marginally during the three and nine months ended September 30, 2015 compared to the corresponding periods in 2014 due primarily to higher weighted-average Revolver borrowings outstanding during the 2015 periods.

Derivatives

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

	Three Months Ended								Nine Months Ended
	September 30,					2015 vs.			September 30,						2015 vs.
	2015		2014			2014			2015			2014			2014
						Favorable (unfavorable)									Favorable (unfavorable)
Oil and gas derivatives settled	$	32,258	$	(7,557	)	$	39,815		$	104,590		$	(17,836	)	$	122,426
Oil and gas derivatives gain (loss)	12,443		74,014			(61,571		)	(52,517		)	25,966			(78,483		)
	$	44,701	$	66,457		$	(21,756	)	$	52,073		$	8,130		$	43,943

We received cash settlements of $32.3 million and $103.9 million, respectively, for crude oil derivatives during the three and nine months ended September 30, 2015 and paid settlements of $7.6 million and $16.0 million, respectively, during the three and nine months ended September 30, 2014. We had no natural gas derivatives outstanding during the three months ended September 30, 2015. We received natural gas cash settlements of $0.7 million during the nine months ended September 30, 2015 and received settlements of $0.1 million and paid settlements of $1.8 million, respectively, during the three and nine months ended September 30, 2014.

37

Income Taxes

	Three Months Ended								Nine Months Ended
	September 30,						2015 vs.		September 30,						2015 vs.
	2015			2014			2014		2015			2014			2014
							Favorable (unfavorable)								Favorable (unfavorable)
Income tax (expense) benefit	$	624		$	(42,113	)	$	42,737	$	394		$	339		$	55
Effective tax rate	2.5		%	32.0		%			0.4		%	4.4		%

We recognized a federal income tax benefit for the three and nine months ended September 30, 2015 at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of recent cumulative losses. The income tax provision includes a benefit of $0.7 million attributable to a federal return to provision adjustment and a minimal deferred state income tax expense of $0.3 million resulting in a combined effective tax rate of 0.4% for the nine months ended September 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.4% is due primarily to the valuation allowance placed against our deferred tax assets.

We recognized income tax benefit for the nine months ended September 30, 2014 at effective rate of 4.4% which reflects the adverse effects of losses incurred in jurisdictions for which we may not realize tax benefits and recorded a valuation allowance against the related deferred tax assets.

38

Critical Accounting Estimates

The process of preparing financial statements in accordance with U.S. GAAP 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, 2014.

New Accounting Standards

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs, or ASU 2015–03, on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7 to the Condensed Consolidated Financial Statements) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10 to the Condensed Consolidated Financial Statements) as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update).

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. In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, that defers by one year the effective date of ASU 2014–09 to fiscal years beginning after December 17, 2017, or calendar year 2018 for us. 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

All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Accordingly, our interest rate risk is attributable to our borrowings under the Revolver, which is subject to variable interest rates. As of September 30, 2015, we had borrowings of $140 million under the Revolver at an interest rate of 2.000%. Assuming a constant borrowing level of $140 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest payments of approximately $1.4 million on an annual basis.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars and swaps) 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, 2015, 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 four 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, 2015, we reported net commodity derivative gains of $52.1 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.

39

The following table sets forth our commodity derivative positions as of September 30, 2015:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2015 1	Collars	3,000	$	86.67	$	94.73	$	6,817	$	—
Fourth quarter 2015 1	Swaps	8,000	$	91.06			26,603		—
First quarter 2016	Swaps	6,000	$	80.41			17,903		—
Second quarter 2016	Swaps	6,000	$	80.41			17,154		—
Third quarter 2016	Swaps	6,000	$	80.41			16,764		—
Fourth quarter 2016	Swaps	6,000	$	80.41			16,150		—
Settlements to be received in subsequent period							10,970		—

_______________________

¹ Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015.

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	$	(27.5	)	$	27.4
Effect on the remainder of 2015 operating income, excluding crude oil derivatives	$	9.1		$	(9.1	)
Effect on the remainder of 2015 operating income, excluding natural gas derivatives	$	1.5		$	(1.5	)

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, 2015. 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, 2015, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended September 30, 2015, 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.

40

Part II. OTHER INFORMATION

Item 1 Legal Proceedings

See Note 11 to our Condensed Consolidated Financial Statements included in Item 1 “Financial Statements,” for a more detailed discussion of our legal contingencies. We are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Item 1A Risk Factors

Our business and operations are subject to a number of risks and uncertainties as described in Item 1A to our Annual report on Form 10-K for the year ended December 31, 2014 and as set forth below.

We have received a notice of failure to comply with the NYSE continued listing standard related to the minimum trading price of our common stock. If we are unable to avoid the delisting of our common stock on the NYSE, it could have a substantial effect on the Company’s liquidity and results of operations.

On September 14, 2015, we were notified by the NYSE that the average closing price of our common stock had fallen below $1.00 per share over a period of 30 consecutive trading days, which is the minimum average share price required by the NYSE.

Under the NYSE rules, we generally have six months following receipt of the notification to regain compliance with the minimum share price requirement, after which the NYSE will commence suspension of trading and delisting procedures. We can regain compliance at any time during the six-month cure period if our common stock has a closing share price of at least $1.00 on the last trading day of any calendar month during the period and also has an average closing share price of at least $1.00 over the 30-trading day period ending on the last trading day of that month or on the last day of the cure period.

Although we are exploring strategic alternatives to improve our liquidity in order to cure the stock price deficiency and return to compliance with the NYSE continued listing requirement, we can provide no assurance that these measures will be successful. The delisting of our common shares from the NYSE could result in even further reductions in our share price, would substantially limit the liquidity of our common shares, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NYSE could also have other negative results, including the potential loss of confidence by investors.

Item 6 Exhibits

(2.1)	Purchase and Sale Agreement dated as of July 15, 2015 by and between Penn Virginia Oil & Gas, L.P., as seller, and Covey Park Energy LLC, as buyer (incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on September 2, 2015).
(3.1)	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on October 29, 2015).
(10.1)	Amended and Restated Construction and Field Gathering Agreement dated as of September 24, 2015 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

41

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
November 9, 2015	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)

42

EX-10.1

Exhibit 10.1

AMENDED AND RESTATED

CONSTRUCTION AND FIELD GATHERING AGREEMENT

by and between

REPUBLIC MIDSTREAM, LLC

(“Gatherer”)

and

PENN VIRGINIA OIL & GAS, L.P.

(“Shipper”)

Dated September 24, 2015

Exhibit 10.1

TABLE OF CONTENTS

Page

ARTICLE I DEFINITIONS1

ARTICLE II DEDICATION AND COMMITMENT6

ARTICLE III CONSTRUCTION and OWNERSHIP OF THE GATHERING SYSTEM; CONSTRUCTION SCHEDULE8

ARTICLE IV CHARACTERISTICS OF THE GATHERING SYSTEM11

ARTICLE V QUANTITY, NOMINATION AND IMBALANCE PROCEDURES12

ARTICLE VI CONTROL OF OIL13

ARTICLE VII MEASUREMENT AND TESTING14

ARTICLE VIII QUALITY14

ARTICLE IX MINIMUM VOLUME COMMITMENT; FEES14

ARTICLE X TERM15

ARTICLE XI STATEMENTS AND PAYMENTS15

ARTICLE XII REGULATION16

ARTICLE XIII TAXES AND ROYALTIES17

ARTICLE XIV REPRESENTATIONS AND WARRANTIES18

ARTICLE XV E    ASEMENTS18

ARTICLE XVI INDEMNITY19

ARTICLE XVII NOTICES AND STATEMENTS20

ARTICLE XVIII FORCE MAJEURE21

ARTICLE XIX CONFIDENTIAL INFORMATION21

ARTICLE XX ASSIGNMENT OR SALE OF GATHERING SYSTEM22

ARTICLE XXI MISCELLANEOUS23

EXHIBITS

EXHIBIT A-1DEDICATION AREA

EXHIBIT A-2INITIAL WELLS

EXHIBIT BNOMINATION PROCEDURES

EXHIBIT CMEASUREMENT AND TESTING

EXHIBIT DREQUIRED INSURANCE

EXHIBIT EFORM OF MEMORANDUM OF DEDICATION - GONZALES

EXHIBIT F FORM OF MEMORANDUM OF DEDICATION - LAVACA

EXHIBIT G DESIGN PROPOSAL

EXHIBIT HFORM OF TARIFF

EXHIBIT IFORM OF MEMORANDUM OF DEDICATION - FAYETTE

Exhibit 10.1

CONSTRUCTION AND FIELD GATHERING AGREEMENT

THIS AMENDED AND RESTATED CONSTRUCTION AND FIELD GATHERING AGREEMENT (this “Agreement”) is made and entered into this 24^th day of September, 2015 (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.” This Agreement supersedes and replaces that certain Construction and Field Gathering Agreement dated July 30, 2014, as amended, by and between 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

Exhibit 10.1

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.

“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 related to the Initial Wells 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-1.

“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”

Exhibit 10.1

on the map attached hereto as Exhibit A-1.

“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.

“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-1.

“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

Exhibit 10.1

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.

“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.

“Initial Wells” means the wells of Shipper identified on Exhibit A-2 attached hereto.

“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).

Exhibit 10.1

“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.

“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.

Exhibit 10.1

“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.

“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, trucking 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.

Exhibit 10.1

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 located in the Core Units and deliver an Equivalent Volume to the Delivery Points. In the event that any Receipts Points in the Core Units are not connected to the Gathering System, Gatherer shall provide trucking services sufficient to transport all of Shipper’s Oil tendered by Shipper each Day at such Receipt Points and deliver an Equivalent Volume to the Delivery Points. If Gatherer elects to take truck delivery by a third party common carrier, Gatherer shall immediately notify Shipper of the carrier’s name and address. Gatherer shall furnish to Shipper delivery tickets for all volumes of Shipper’s Oil trucked from the Receipt 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.

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.

Exhibit 10.1

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.

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, 2015, 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 Initial Wells are connected to the Gathering System, and the Base Gathering System and CDP are operational, by not later than January 1, 2016 (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:

Exhibit 10.1

(a)    Shipper shall notify Gatherer of the need to construct and install an Additional Segment to connect 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 connect such additional Receipt Point to the Gathering System (it being understood that Gatherer must connect (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 connect any additional Receipt Point pursuant to this Section 3.2 in a production unit which already has a Receipt Point connected to the Gathering System (subject to the following proviso) if the aggregate Receipt Points connected to the Gathering System 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 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 connect 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

Exhibit 10.1

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.

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. If (a) the Completion Date for an Additional Segment has not occurred within 120 Days after 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) for a period of 120 Days, Shipper may request that Gatherer release the wells connected to such Additional Segment from the Dedication Area, and Gatherer shall grant such dedication release and promptly deliver a recordable copy of such dedication release to Shipper.

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,

Exhibit 10.1

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. In the event that trucking services are required to be provided by Gatherer, Gatherer shall provide such services in accordance with the terms of 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;

(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 six dual LACT/ACT Units; provided, however, that should Shipper determine that six dual LACT/ACT Units are not sufficient for loading and unloading Shipper’svolumes, Shipper shall provide written notice of such to Gatherer and Gatherer shall install, within sixty (60) Days of receipt of such notice, up to two additional LACT/ACT Units;

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

Exhibit 10.1

(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.

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 Article II.

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.

Exhibit 10.1

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 trucks and 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.

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.

Exhibit 10.1

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.

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, (a) volume shall be calculated based on the trailing three (3) Month average volume gathered by Gatherer on the Gathering System and trucked by Gatherer pursuant to this Agreement and (b) volumes gathered via the Gathering System shall be counted before volumes trucked by Gatherer. 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”):

Exhibit 10.1

(a)    A Gathering Fee on all of Shipper’s Oil delivered at the Delivery Points via the Gathering System 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	$1.75 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 via the Gathering System 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 Trucking Fee equal to (x) $1.75 per Barrel on all of Shipper’s Oil trucked by Gatherer from the Receipt Points to the CDP or any other Delivery Point until such time as Shipper has delivered the Minimum Volume Commitment and (y) $1.25 per Barrel on all additional Shipper’s Oil trucked by Gatherer from the Receipt Points to the CDP or any other Delivery Point above the Minimum Volume Commitment.

(d)    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; provided, however, that no Truck Loading Fee shall apply to any Barrels of Shipper’s Oil trucked by Gatherer pursuant to the terms of this Agreement.

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.

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

Exhibit 10.1

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.

11.1    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.

11.2    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 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.

Exhibit 10.1

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.

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

Exhibit 10.1

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.

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,

Exhibit 10.1

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.

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 HEREWITH IN 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.

Exhibit 10.1

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
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

Exhibit 10.1

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.

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;

Exhibit 10.1

(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 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,

Exhibit 10.1

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 Dedication 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.

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

Exhibit 10.1

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]

Exhibit 10.1

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/ Jill T. Zively

Name:    Jill T. Zivley

Title:    Vice President, Oil & Gas Marketing

Exhibit 10.1

EXHIBIT A-1

DEDICATION AREA

See attached map

Exhibit 10.1

EXHIBIT A-2

INITIAL WELLS

Chicken Hawk 1H

Jake Berger Cattle Co 1H

Dingo Hunter 1H, 2H, 3H

Leopard Hunter 1H, 4H, 5H, 6H, 7H

Wombat Hunter 1H, 2H, 3H, 4H

Bertha 2H, 3H, 4H

Hefe Hunter 2H,3H, 4H

Hefe Hunter 5H,6H, 7H

Pilsner Hunter 2H, 3H, 4H, 5H

Blonde 2H, 3H, 4H, 5H

Blonde 6H, 7H, 8H, 9H

Blonde 1H

Bock 1H, 2H, 3H

Porter 3H, 4H, 5H, 9H

Rhino 6H, 7H

Effenberger 4H, 5H

Zebra Hunter 2H, 3H

Lager 1H, 2H

Exhibit 10.1

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.

Exhibit 10.1

EXHIBIT C

MEASUREMENT AND TESTING

1. Crude Oil shall be measured by LACT/ACT Units installed, maintained and operated by Gatherer or its designee, in the case of Crude Oil gathered via the Gathering System, or from static tank gauges on 100% tank table basis (or by use of mutually acceptable automatic measuring equipment), in the case of Crude Oil trucked by Gatherer, 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, in the case of Crude Oil gathered via the Gathering System, or from static tank gauges on 100% tank table basis (or by use of mutually acceptable automatic measuring equipment), in the case of Crude Oil trucked by Gatherer. 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

Exhibit 10.1

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.

8. Notwithstanding anything to the contrary, all measurement, testing procedures and computations shall be made in accordance with current API standards.

Exhibit 10.1

EXHIBIT D

REQUIRED INSURANCE

See attached

Exhibit 10.1

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 AMENDED AND RESTATED CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of September 16, 2015 (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-five (25) 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]

Exhibit 10.1

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:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Penn Virginia Oil & Gas GP LLC, a __________ limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

Exhibit 10.1

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

Exhibit 10.1

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 AMENDED AND RESTATED CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of September 16, 2015 (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-five (25) 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]

Exhibit 10.1

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:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Penn Virginia Oil & Gas GP LLC, a __________ limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

Exhibit 10.1

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

Exhibit 10.1

EXHIBIT G

DESIGN PROPOSAL

See attached

Exhibit 10.1

EXHIBIT H

TARIFF

See attached

Exhibit 10.1

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 AMENDED AND RESTATED CONSTRUCTION AND FIELD GATHERING AGREEMENT dated as of September 16, 2015 (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-five (25) 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]

Exhibit 10.1

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:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Penn Virginia Oil & Gas GP LLC, a __________ limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

GATHERER:

REPUBLIC MIDSTREAM, LLC

By:    ____________________________

Name:    

Title:    

STATE OF _____________    §

§

COUNTY OF _____________    §

This instrument was acknowledged before me on _____________, 2015 by _____________, __________________________ of Republic Midstream, LLC, a Delaware limited liability company, on behalf of said company.

Notary Public in and for

The State of ________________

Exhibit 10.1

Exhibit A to

MEMORANDUM OF DEDICATION

Dedication Area

(See Attached)

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,
	2015			2014			2013			2012			2011			2010
Earnings:
Income (loss) from continuing operations before income taxes	$	(111,788	)	$	(541,270	)	$	(220,766	)	$	(173,291	)	$	(221,070	)	$	(108,178	)
Fixed charges	92,943			121,608			97,903			66,616			62,002			60,003
Capitalized interest	(4,854		)	(7,232		)	(5,266		)	(803		)	(1,983		)	(1,384		)
Preferred stock dividend requirements	(18,133		)	(22,661		)	(10,647		)	(2,793		)	—			—
	$	(41,832	)	$	(449,555	)	$	(138,776	)	$	(110,271	)	$	(161,051	)	$	(49,559	)
Fixed charges:
Interest expense	$	68,021		$	88,831		$	78,841		$	59,339		$	56,216		$	53,679
Capitalized interest	4,854			7,232			5,266			803			1,983			1,384
Rent factor	1,935			2,884			3,149			3,681			3,803			4,940
Preferred stock dividend requirements	18,133			22,661			10,647			2,793			—			—
	$	92,943		$	121,608		$	97,903		$	66,616		$	62,002		$	60,003
Ratio of earnings to fixed charges and preferred stock dividends 1	—			—			—			—			—			—

¹ During the nine months ended September 30, 2015, earnings were deficient by $134,775. During the years ended December 31, 2014, 2013, 2012, 2011 and 2010, earnings were deficient by $571,163, $236,679, $176,887, $223,053 and $109,562, 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, Edward B. Cloues, II, Chairman 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: November 9, 2015

/s/ EDWARD B. CLOUES, II

Edward B. Cloues, II

Chairman 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: November 9, 2015

/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, 2015, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Edward B. Cloues, II, Chairman 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: November 9, 2015

/s/ EDWARD B. CLOUES, II

Edward B. Cloues, II

Chairman 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, 2015, 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: November 9, 2015

/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

Accounts Receivable and Major Customers - Additional Information (Detail) $ in Millions	9 Months Ended		12 Months Ended
	Sep. 30, 2015 USD ($) Customer	Sep. 30, 2014 USD ($) Customer	Dec. 31, 2014 USD ($)
Sales Revenue | Customer Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Number of major customers | Customer	2	4
Revenues, major customers	$ 108.4	$ 267.0
Concentration risk, percentage	50.00%	65.00%
Sales Revenue | Customer Concentration Risk | Major Customer 1
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 62.3	$ 86.2
Concentration risk, percentage	29.00%	21.00%
Sales Revenue | Customer Concentration Risk | Major Customer 2
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers	$ 46.1	$ 72.5
Concentration risk, percentage	21.00%	18.00%
Sales Revenue | Customer Concentration Risk | Major Customer 3
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 55.7
Concentration risk, percentage		13.00%
Sales Revenue | Customer Concentration Risk | Major Customer 4
Accounts, Notes, Loans and Financing Receivable [Line Items]
Revenues, major customers		$ 52.6
Concentration risk, percentage		13.00%
Accounts Receivable | Credit Concentration Risk
Accounts, Notes, Loans and Financing Receivable [Line Items]
Concentration risk, percentage	45.00%		63.00%
Accounts receivable, major customers	$ 16.5		$ 39.3

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Shareholders' Equity Rollforward (Details) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Schedule of Stockholders' Equity [Line Items]
Preferred Stock, Value, Issued	[1]			$ 0	$ 313,330
Share-based compensation				$ 3,369	$ 2,638
Stock Issued During Period, Shares, Conversion of Convertible Securities				1,458,336	5,924,706
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				$ 675,817	$ 788,804
Net income (loss)		$ 25,900	$ 89,661	(111,394)	8,102
Dividends Declared	[1]			(12,134)
Dividends Declared					(11,081)
All Other Changes	[2]			2,782	(488)
As of ending balance		555,071	1,098,667	555,071	1,098,667
Preferred stock dividends	[3]	(5,935)	(7,641)	(18,069)	(11,081)
Less: Induced conversion of preferred stock		0	(888)	0	(4,256)
Preferred stock
Schedule of Stockholders' Equity [Line Items]
Preferred Stock, Value, Issued					3,250
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				4,044	1,150
All Other Changes	[2]			(87)	(356)
As of ending balance		3,957	4,044	3,957	4,044
Common stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				529	466
All Other Changes	[2]			19	62
As of ending balance		548	528	548	528
Paid-in capital
Schedule of Stockholders' Equity [Line Items]
Preferred Stock, Value, Issued					310,080
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				1,206,305	891,351
All Other Changes	[2]			2,882	3,871
As of ending balance		1,209,187	1,205,302	1,209,187	1,205,302
Accumulated deficit
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				(535,176)	(104,180)
Net income (loss)				(111,394)
All Other Changes	[2]				(4,256)
As of ending balance		(658,704)	(111,415)	(658,704)	(111,415)
Preferred stock dividends	[1]			(12,134)	(11,081)
Deferred compensation obligation
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				3,211	2,792
All Other Changes	[2]			229	314
As of ending balance		3,440	3,106	3,440	3,106
Accumulated other comprehensive income
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance	[4]			249	267
All Other Changes	[4]			(32)	74
As of ending balance	[4]	217	341	217	341
Treasury stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
As of beginning balance				(3,345)	(3,042)
All Other Changes	[2]			(229)	(197)
As of ending balance		$ (3,574)	$ (3,239)	$ (3,574)	(3,239)
Series A Preferred Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Less: Induced conversion of preferred stock					$ (4,300)
Convertible Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Conversion of Stock, Shares Converted				875	3,555

[1] Includes dividends declared of $300.00 per share and $450.00 per share of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the nine months ended September 30, 2015 and 2014, respectively, and $300.00 per share and $198.33 per share of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the nine months ended September 30, 2015 and 2014, respectively.

[2] Includes equity-classified share-based compensation of $3,369 and $2,638 for the nine months ended September 30, 2015 and 2014, respectively.

[3] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

[4] 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, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(49) and $114 and are presented above net of taxes of $(17) and $40, respectively.

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Firm Transportation Obligation - Additional Information (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Firm Transportation Obligation [Line Items]
Balance of obligation, noncurrent	$ 11,068	$ 12,042
Accounts Payable and Accrued Liabilities
Firm Transportation Obligation [Line Items]
Balance of obligation, current	2,800
Other Noncurrent Liabilities
Firm Transportation Obligation [Line Items]
Balance of obligation, noncurrent	$ 11,000

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Long-Term Debt - Additional Information (Detail) - USD ($)	9 Months Ended
	Sep. 30, 2015	Nov. 09, 2015	Jun. 30, 2015	Dec. 31, 2014
Revolving Credit Facility
Debt Disclosure [Line Items]
Borrowing base and revolving commitment	$ 395,000,000		$ 425,000,000
Letters of credit amount outstanding	1,800,000
Available borrowing capacity	$ 253,200,000
Interest rate option two, base rate over federal funds effective rate	0.50%
Debt Instrument, Description of Variable Rate Basis	one-month Adjusted LIBOR
Interest rate option two, base rate over one-month Adjusted LIBOR	1.00%
Interest rate option two, applicable margin rate	1.75%
Commitment Fee Percentage at Period End	0.375%
Interest Rate at Period End	2.00%
Interest Rate at Period End, LIBOR component	0.25%
Revolving Credit Facility | Minimum
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR	1.50%
Interest rate option two, applicable margin rate	0.50%
Commitment fees for undrawn credit facility	0.375%
Covenant requirement - Current ratio	1.0
Revolving Credit Facility | Maximum
Debt Disclosure [Line Items]
Interest rate option one, applicable margin rate over Adjusted LIBOR	2.50%
Interest rate option two, applicable margin rate	1.50%
Commitment fees for undrawn credit facility	0.50%
Revolving Credit Facility | Through March 31, 2016
Debt Disclosure [Line Items]
Covenant requirement - Debt to EBITDAX ratio	4.75
Revolving Credit Facility | Through June 30, 2016 (TTM)
Debt Disclosure [Line Items]
Covenant requirement - Debt to EBITDAX ratio	5.25
Revolving Credit Facility | Through December 31, 2016 (TTM)
Debt Disclosure [Line Items]
Covenant requirement - Debt to EBITDAX ratio	5.50
Revolving Credit Facility | Through March 31, 2017 (TTM)
Debt Disclosure [Line Items]
Covenant requirement - Debt to EBITDAX ratio	4.50
Covenant requirement - Senior Secured Debt to EBITDAX ratio	2.75
Revolving Credit Facility | Through maturity in September 2017 (TTM)
Debt Disclosure [Line Items]
Covenant requirement - Debt to EBITDAX ratio	4.0
Debt to EBITDAX Ratio that precludes the payment of cash dividends on preferred stock	5.0
Revolving Credit Facility | Letter of Credit
Debt Disclosure [Line Items]
Maximum borrowing capacity	$ 20,000,000
7.25% Senior Notes due 2019
Debt Disclosure [Line Items]
Senior Notes, Noncurrent	$ 300,000,000			$ 300,000,000
Annual interest rate	7.25%
7.25% Senior Notes due 2019 | Through March 31, 2016
Debt Disclosure [Line Items]
Redemption option, percent of principal	103.625%
7.25% Senior Notes due 2019 | Through December 31, 2016 (TTM)
Debt Disclosure [Line Items]
Redemption option, percent of principal	100.00%
8.50% Senior Notes due 2020
Debt Disclosure [Line Items]
Senior Notes, Noncurrent	$ 775,000,000			$ 775,000,000
Annual interest rate	8.50%
Subsequent Event | Revolving Credit Facility
Debt Disclosure [Line Items]
Borrowing base and revolving commitment		$ 275,000,000

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015			2014			2015			2014
Equity-classified awards:
Stock option awards	$	462		$	403		$	1,242		$	1,193
Common, deferred and restricted stock and stock unit awards	801			584			2,127			1,445
	1,263			987			3,369			2,638
Liability-classified awards	(851		)	(360		)	(686		)	6,632
	$	412		$	627		$	2,683		$	9,270

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Components of Interest Expense (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Banking and Thrift [Abstract]
Interest on borrowings and related fees	$ 23,239	$ 22,559	$ 69,371	$ 69,477
Amortization of debt issuance costs	1,224	1,063	3,504	3,114
Capitalized interest	(1,478)	(1,669)	(4,854)	(4,875)
Interest expense	$ 22,985	$ 21,953	$ 68,021	$ 67,716

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Accounts Receivable and Major Customers (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015			2014
Customers	$	37,010		$	62,650
Joint interest partners	29,693			120,708
Other	7,872			6,549
	74,575			189,907
Less: Allowance for doubtful accounts	(1,555		)	(280		)
	$	73,020		$	189,627

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Components of Selected Balance Sheet Accounts (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Asset Impairment Charges	$ 0	$ 6,084	$ 1,084	$ 123,992
Other current assets:
Tubular inventory and well materials	2,925		2,925		$ 5,802
Prepaid expenses	3,614		3,614		4,215
Other Assets, Miscellaneous, Current	763		763		97
Other Assets, Current	7,302		7,302		10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	4,014		4,014		4,123
Deferred issuance costs of the Revolver	1,796		1,796		1,623
Other	26		26		95
Other assets	5,836		5,836		5,841
Accounts payable and accrued liabilities:
Trade accounts payable	24,768		24,768		122,994
Drilling and other lease operating costs	26,643		26,643		68,842
Royalties and revenue – related	52,062		52,062		78,359
Compensation – related	12,853		12,853		9,197
Interest	37,438		37,438		15,555
Preferred stock dividends	0		0		6,067
Other	8,144		8,144		11,213
Accounts payable and accrued liabilities	161,908		161,908		312,227
Other liabilities:
Deferred gains on sale of assets	82,944		82,944		90,569
Firm transportation obligation	11,068		11,068		12,042
Asset retirement obligations	2,570		2,570		5,889
Defined benefit pension obligations	1,508		1,508		1,753
Postretirement health care benefit obligations	965		965		890
Compensation-related	1,150		1,150		7,631
Deferred compensation – SERP obligations and other	4,020		4,020		4,183
Other	1,012		1,012		929
Other liabilities	$ 105,237		$ 105,237		$ 123,886

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Impact of Derivative Activities on Condensed Consolidated Statements of Income (Detail) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivatives	$ 44,701	$ 66,457	$ 52,073	$ 8,130
Commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Cash Received on Hedge	32,258	(7,557)	104,590	(17,836)
Unrealized gains (losses)	$ 12,443	$ 74,014	$ (52,517)	$ 25,966

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Divestitures - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended					3 Months Ended				9 Months Ended
	Oct. 31, 2015	Sep. 30, 2015	Aug. 31, 2015	May. 31, 2015	Jul. 31, 2014	Dec. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2015	Sep. 30, 2014
Divestitures [Line Items]
Balance of deferred gain recognized in period										$ 0.3
East Texas
Divestitures [Line Items]
Proceeds from sale of oil and gas properties before closing adjustments			$ 73.0
Gain on Sale of Oil and Gas Property				$ 43.0
Disposal Group, Including Discontinued Operation, Assets				28.5
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment				32.3
Disposal Group, Including Discontinued Operation, Asset Retirement Obligation				$ 3.8
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax							$ 1.0	$ (6.9)		1.7	$ (18.4)
South Texas Oil Gathering Sys. Development Rights
Divestitures [Line Items]
Proceeds from Sale of Intangible Assets					$ 147.0
Sale Leaseback Transaction, Recognized Gain, Net					63.0
Sale Leaseback Transaction, Deferred Gain, Gross					$ 84.1
Period over which deferred gain is being recognized					25 years
Balance of deferred gain recognized in period		$ 8.4
Deferred gain on sale of assets, current component		2.3					2.3			2.3
Deferred gain on sale of assets, noncurrent component		73.5					73.5			73.5
Gain on Disposition of Assets					$ 147.1
South Texas Natural Gas Gathering Assets
Divestitures [Line Items]
Proceeds from sale of oil and gas properties before closing adjustments									$ 96.0
Gain on Sale of Oil and Gas Property									67.3
Sale Leaseback Transaction, Recognized Gain, Net									56.7
Sale Leaseback Transaction, Deferred Gain, Gross									$ 10.6
Period over which deferred gain is being recognized									25 years
Deferred gain on sale of assets, current component		0.4					0.4			0.4
Deferred gain on sale of assets, noncurrent component		$ 9.5					$ 9.5			$ 9.5
Subsequent Event | Eagle Ford Shale, Lavaca County
Divestitures [Line Items]
Proceeds from sale of oil and gas properties before closing adjustments	$ 13.0
Scenario, Forecast | Eagle Ford Shale, Lavaca County
Divestitures [Line Items]
Gain on Sale of Oil and Gas Property						$ 9.0

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Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Assets:
Commodity derivative assets – current	$ 96,211	$ 128,981
Commodity derivative assets – noncurrent	16,149	35,897
Liabilities:
Commodity derivative liabilities – current	0	0
Fair Value, Measurements, Recurring
Assets:
Assets of SERP	4,014	4,123
Liabilities:
Deferred compensation – SERP obligations	4,019	(4,178)
Fair Value, Measurements, Recurring | Level 1
Assets:
Assets of SERP	4,014	4,123
Liabilities:
Deferred compensation – SERP obligations	4,019	(4,178)
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
Assets:
Commodity derivative assets – current	96,211	128,981
Commodity derivative assets – noncurrent	16,149	35,897
Fair Value, Measurements, Recurring | Commodity contracts | Level 1
Assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – noncurrent	0	0
Fair Value, Measurements, Recurring | Commodity contracts | Level 2
Assets:
Commodity derivative assets – current	96,211	128,981
Commodity derivative assets – noncurrent	16,149	35,897
Fair Value, Measurements, Recurring | Commodity contracts | Level 3
Assets:
Commodity derivative assets – current	0	0
Commodity derivative assets – noncurrent	$ 0	$ 0

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Income Taxes (Details) - USD ($) $ in Millions	1 Months Ended	9 Months Ended
	Oct. 31, 2015	Sep. 30, 2015	Sep. 30, 2014
Income Tax Disclosure [Abstract]
Effective tax rate (federal and state combined)		0.35%	(4.40%)
Federal statutory income tax rate		35.00%
Federal return to provision adjustment		$ 0.7
Deferred state tax expense		$ 0.3
Federal and state (combined) statutory income tax rate		35.70%
Income taxes paid		$ 0.1	$ 0.1
Subsequent Event
Subsequent Event [Line Items]
Federal income tax refund	$ 0.7

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Basis of Presentation

9 Months Ended

Sep. 30, 2015

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, 2014. Operating results for the nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheet or cash flows.

Going Concern Presumption and Management’s Plans

These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. We have incurred net losses in each of the three years ending December 31, 2014, and reported a net loss attributable to common shareholders of $(129.5) million for the nine months ended September 30, 2015. While we were in compliance with the covenants of our revolving credit agreement (the “Revolver”) as of September 30, 2015, based on our current operating forecast and capital structure, we do not believe we will be able to comply with all of the covenants under the Revolver during the next twelve months. We are also dependent on obtaining additional debt and/or equity financing to continue our planned principal business operations. These factors raise substantial doubt about our ability to continue as a going concern.

Management’s plans in regard to these matters consist principally of restructuring our debt or seeking additional debt or equity funding from outside sources. We are actively working to address these matters, however, there can be no assurance that our efforts will be successful. The Condensed Consolidated Financial Statements do not include any adjustments that may result from the outcome of this uncertainty.

Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering 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. Due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:

• We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period (see Note 12). We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.

• We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015 (see Note 3).

• We suspended the payment of dividends on our convertible preferred stock in September 2015 (see Note 13).

• We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015 (see Note 3).

• We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.

• We engaged Jefferies LLC (“Jefferies”) to advise us with respect to asset-level financing transactions and various financing and debt restructuring options (see Note 12).

While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior subordinated notes become due in April and May of 2016. Moreover, unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016.

Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection.

Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.

New Accounting Pronouncements

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015–03”) on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10) as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

In 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. In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, that defers by one year the effective date of ASU 2014–09 to fiscal years beginning after December 17, 2017, or calendar year 2018 for us. 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.

Subsequent Events

Management has evaluated all activities of the Company through the date upon which our Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of non-core properties in the southwestern portion of our Eagle Ford acreage referenced above and in Note 3, 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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Fair Value of Derivative Instruments on Condensed Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative assets, current	$ 96,211	$ 128,981
Derivative assets, noncurrent	16,149	35,897
Derivative assets	112,360	164,878
Derivative liabilities, current	0	0
Derivative liabilities	0	0
Commodity contracts
Derivatives, Fair Value [Line Items]
Derivative assets	112,400
Commodity contracts | Derivative assets/liabilities - current
Derivatives, Fair Value [Line Items]
Derivative assets, current	96,211	128,981
Derivative liabilities, current	0	0
Commodity contracts | Derivative assets/liabilities - noncurrent
Derivatives, Fair Value [Line Items]
Derivative assets, noncurrent	16,149	35,897
Derivative liabilities, noncurrent	$ 0	$ 0

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Firm Transportation Obligation (Tables)

9 Months Ended

Sep. 30, 2015

Restructuring and Related Activities [Abstract]

Summary of Restructuring Related Obligations

The following table reconciles the obligation as of the dates presented:

	As of
	September 30,			December 31,
	2015			2014
Balance at beginning of period	$	14,790		$	15,993
Accretion	705			1,301
Cash payments, net	(1,691		)	(2,504		)
Balance at end of period	$	13,804		$	14,790

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Carrying Amount of Components of Long-term Debt

The following table summarizes our long-term debt as of the dates presented giving effect to the adoption of ASU 2015–03:

	As of
	September 30, 2015				December 31, 2014
	Principal		Unamortized Issuance Costs		Principal		Unamortized Issuance Costs
Revolving credit facility 1	$	140,000			$	35,000
Senior notes due 2019	300,000		$	3,510	300,000		$	4,131
Senior notes due 2020	775,000		18,128		775,000		20,440
Totals	1,215,000		$	21,638	1,110,000		$	24,571
Long-term debt, net of unamortized issuance costs	$	1,193,362			$	1,085,429

_______________________

¹ Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, are presented as a component of Other assets (see Note 10) in accordance with ASU 2015-15.

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Summary of Share-Based Compensation Expense (Detail) - USD ($) $ in Thousands	3 Months Ended			9 Months Ended
	Sep. 30, 2015	Mar. 31, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Stock option awards	$ 462		$ 403	$ 1,242	$ 1,193
Common, deferred, restricted and restricted unit awards	801		584	2,127	1,445
Share-based compensation				3,369	2,638
Allocated Share-based Compensation Expense	412		627	2,683	9,270
Equity-classified awards:
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Share-based compensation	1,263		987	3,369	2,638
Liability-classified awards
Employee Service Share-based Compensation, Allocation of Recognized Period Costs [Line Items]
Cash paid to settle liability-classified Share-based Award (PBRSUs)		$ 1,500
Share-based compensation	$ (851)		$ (360)	$ (686)	$ 6,632

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Summary of Property and Equipment (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Oil and gas properties:
Proved	$ 2,687,598	$ 3,390,482
Unproved	125,571	125,676
Total oil and gas properties	2,813,169	3,516,158
Other property and equipment	31,423	75,073
Total properties and equipment	2,844,592	3,591,231
Accumulated depreciation, depletion and amortization	(1,026,006)	(1,766,133)
Property and equipment, net (successful efforts method)	$ 1,818,586	$ 1,825,098

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Additional Balance Sheet Detail (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015		2014
Other current assets:
Tubular inventory and well materials	$	2,925	$	5,802
Prepaid expenses	3,614		4,215
Other	763		97
	$	7,302	$	10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	$	4,014	$	4,123
Deferred issuance costs of the Revolver	1,796		1,623
Other	26		95
	$	5,836	$	5,841
Accounts payable and accrued liabilities:
Trade accounts payable	$	24,768	$	122,994
Drilling and other lease operating costs	26,643		68,842
Royalties and revenue – related	52,062		78,359
Compensation – related	12,853		9,197
Interest	37,438		15,555
Preferred stock dividends	—		6,067
Other	8,144		11,213
	$	161,908	$	312,227
Other liabilities:
Deferred gains on sales of assets	$	82,944	$	90,569
Firm transportation obligation	11,068		12,042
Asset retirement obligations	2,570		5,889
Defined benefit pension obligations	1,508		1,753
Postretirement health care benefit obligations	965		890
Compensation – related	1,150		7,631
Deferred compensation – SERP obligations and other	4,020		4,183
Other	1,012		929
	$	105,237	$	123,886

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	68,272	$	300,000	$	234,000	$	300,000
Senior Notes due 2020	197,675		775,000		620,000		775,000
	$	265,947	$	1,075,000	$	854,000	$	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, 2015
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:
Commodity derivative assets – current	$	96,211	$	—	$	96,211	$	—
Commodity derivative assets – noncurrent	16,149		—		16,149		—
Assets of SERP	4,014		4,014		—		—
Liabilities:
Deferred compensation – SERP obligations	4,019		4,019		—		—

	As of December 31, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	128,981		$	—		$	128,981	$	—
Commodity derivative assets – noncurrent	35,897			—			35,897		—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,178		)	(4,178		)	—		—

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Organization

9 Months Ended

Sep. 30, 2015

Accounting Policies [Abstract]

Organization

Organization

Penn Virginia Corporation (together with its consolidated subsidiaries unless the context otherwise requires, “Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the onshore exploration, development and production of oil, natural gas liquids (“NGLs”) and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have less significant operations in Oklahoma, primarily the Granite Wash.

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Shareholders' Equity (Tables)

9 Months Ended

Sep. 30, 2015

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, 2015 and 2014:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2014			Net Loss			Offering		Declared 1			Changes 2			2015
Preferred stock 3	$	4,044		$	—		$	—	$	—		$	(87	)	$	3,957
Common stock 3	529			—			—		—			19			548
Paid-in capital 3	1,206,305			—			—		—			2,882			1,209,187
Accumulated deficit	(535,176		)	(111,394		)	—		(12,134		)	—			(658,704		)
Deferred compensation obligation	3,211			—			—		—			229			3,440
Accumulated other comprehensive income 4	249			—			—		—			(32		)	217
Treasury stock	(3,345		)	—			—		—			(229		)	(3,574		)
	$	675,817		$	(111,394	)	$	—	$	(12,134	)	$	2,782		$	555,071
	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

_______________________

¹ Includes dividends declared of $300.00 per share and $450.00 per share of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the nine months ended September 30, 2015 and 2014, respectively, and $300.00 per share and $198.33 per share of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the nine months ended September 30, 2015 and 2014, respectively.

² Includes equity-classified share-based compensation of $3,369 and $2,638 for the nine months ended September 30, 2015 and 2014, respectively.

³ A total of 875 shares, or 87,500 depositary shares, of the Series A Preferred Stock were converted into 1,458,336 shares of our common stock during the nine months ended September 30, 2015. 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 during the 2014 period.

⁴ 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, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(49) and $114 and are presented above net of taxes of $(17) and $40, respectively.

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Derivative Instruments - Additional Information (Detail) $ in Thousands	9 Months Ended
	Sep. 30, 2015 USD ($) Entity	Dec. 31, 2014 USD ($)
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 112,360	$ 164,878
Commodity contracts
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Derivative assets	$ 112,400
Number of derivative counterparties | Entity	7
Commodity contracts | Credit Concentration Risk
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Number of derivative counterparties | Entity	4
Commodity contracts | Natural Gas
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices	NYMEX Henry Hub gas
Commodity contracts | Crude Oil
Derivative Instruments and Hedging Activities Disclosure [Line Items]
Third-party quoted forward prices	West Texas Intermediate crude oil

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Commitments and Contingencies - Additional Information (Detail) - USD ($) shares in Millions, $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Jul. 31, 2015	Sep. 30, 2015	Sep. 30, 2015	Dec. 31, 2010
Commitments and Contingencies Disclosure [Line Items]
Restructuring advisory fees, shares	6.5
Asset retirement obligations		$ 2.6	$ 2.6
Legal Reserve
Commitments and Contingencies Disclosure [Line Items]
Reserve established for contingency matters				$ 0.9
Contract Drilling
Commitments and Contingencies Disclosure [Line Items]
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			$ 3.4
Contractual obligation, early termination fee			6.2
Contractual obligation, balance of 2015		2.4	2.4
Contractual obligation, 2016		0.8	0.8
Coil Tubing Services
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, balance of 2015		1.0	1.0
Firm Transportation
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, balance of 2015		0.5	0.5
Firm Transportation | Through 2028
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, annual		$ 1.1	1.1
Firm Transportation | Maximum
Commitments and Contingencies Disclosure [Line Items]
Contract term		13 years
Gas Gathering And Compression Services
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, balance of 2015		$ 1.1	1.1
Contractual obligation, 2016		5.0	5.0
Crude Oil Gathering And Transportation Services
Commitments and Contingencies Disclosure [Line Items]
Contractual obligation, annual		12.3	12.3
Drilling Carry
Commitments and Contingencies Disclosure [Line Items]
Contractual Obligation		$ 10.7	$ 10.7

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CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Revenues
Crude oil		$ 51,124	$ 118,716	$ 180,964	$ 336,382
Natural gas liquids (NGLs)		3,254	9,790	13,841	27,200
Natural gas		6,312	13,354	22,143	47,859
Gain (loss) on sales of property and equipment, net		50,828	63,520	50,803	120,295
Other, net		466	16	2,376	2,886
Total revenues		111,984	205,396	270,127	534,622
Operating expenses
Lease operating		11,304	14,761	33,780	36,878
Gathering, processing and transportation		5,654	5,428	19,535	12,605
Production and ad valorem taxes		3,483	7,690	13,139	22,505
General and administrative		9,416	11,527	32,865	43,055
Exploration		1,673	1,986	11,922	13,995
Depreciation, depletion and amortization		76,850	71,999	253,056	215,623
Impairments		0	6,084	1,084	123,992
Total operating expenses		108,380	119,475	365,381	468,653
Operating income (loss)		3,604	85,921	(95,254)	65,969
Other income (expense)
Interest expense		(22,985)	(21,953)	(68,021)	(67,716)
Derivatives		44,701	66,457	52,073	8,130
Other		(44)	1,349	(586)	1,380
Income (loss) before income taxes		25,276	131,774	(111,788)	7,763
Income tax (expense) benefit		624	(42,113)	394	339
Net income (loss)		25,900	89,661	(111,394)	8,102
Preferred stock dividends	[1]	(5,935)	(7,641)	(18,069)	(11,081)
Less: Induced conversion of preferred stock		0	(888)	0	(4,256)
Net income (loss) attributable to common shareholders		$ 19,965	$ 81,132	$ (129,463)	$ (7,235)
Net income (loss) per share:
Basic (in dollars per share)		$ 0.27	$ 1.13	$ (1.79)	$ (0.11)
Diluted (in dollars per share)		$ 0.25	$ 0.87	$ (1.79)	$ (0.11)
Weighted average shares outstanding – basic		72,651	71,536	72,438	67,909
Weighted average shares outstanding – diluted		103,452	103,606	72,438	67,909

[1] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

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Summary of Long-Term Debt (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving credit facility	$ 140,000	$ 35,000
Long-term debt, gross	1,215,000	1,110,000
Unamortized issuance costs	21,638	24,571
Long-term debt, net	1,193,362	1,085,429
7.25% Senior Notes due 2019
Debt Instrument [Line Items]
Senior notes	300,000	300,000
Unamortized issuance costs	3,510	4,131
8.50% Senior Notes due 2020
Debt Instrument [Line Items]
Senior notes	775,000	775,000
Unamortized issuance costs	$ 18,128	$ 20,440

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CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Schedule of Stockholders' Equity [Line Items]
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	228,000,000
Common stock, shares issued	73,297,205	71,568,936
Treasury stock, shares	455,689	262,070
Series A Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	7,070	7,945
Series B Preferred Stock
Schedule of Stockholders' Equity [Line Items]
Preferred stock, issued	32,500	32,500

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Earnings per Share (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015			2014			2015			2014
Net income (loss)	$	25,900		$	89,661		$	(111,394	)	$	8,102
Less: Preferred stock dividends	(5,935		)	(7,641		)	(18,069		)	(11,081		)
Less: Induced conversion of preferred stock	—			(888		)	—			(4,256		)
Net income (loss) attributable to common shareholders – basic	$	19,965		$	81,132		$	(129,463	)	$	(7,235	)
Add: Preferred stock dividends 1	5,935			7,641			—			—
Add: Induced conversion of preferred stock 1	—			888			—			—
Net income (loss) attributable to common shareholders – diluted	$	25,900		$	89,661		$	(129,463	)	$	(7,235	)
Weighted-average shares – basic	72,651			71,536			72,438			67,909
Effect of dilutive securities 2	30,801			32,070			—			—
Weighted-average shares – diluted	103,452			103,606			72,438			67,909

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015 and 2014, approximately 31.1 millionand24.9 million, respectively, of 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.

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Interest Expense

9 Months Ended

Sep. 30, 2015

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,
	2015			2014			2015			2014
Interest on borrowings and related fees	$	23,239		$	22,559		$	69,371		$	69,477
Amortization of debt issuance costs	1,224			1,063			3,504			3,114
Capitalized interest	(1,478		)	(1,669		)	(4,854		)	(4,875		)
	$	22,985		$	21,953		$	68,021		$	67,716

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Basis of Presentation (Details) - USD ($) $ in Thousands	1 Months Ended		3 Months Ended		9 Months Ended
	Oct. 31, 2015	Aug. 31, 2015	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accounting Policies [Abstract]
Net income (loss) attributable to common shareholders			$ 19,965	$ 81,132	$ (129,463)	$ (7,235)
Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of positions eliminated, inception to date percent	16.00%
East Texas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties before closing adjustments		$ 73,000
Eagle Ford Shale, Lavaca County | Subsequent Event
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of oil and gas properties before closing adjustments	$ 13,000

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Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2015

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, 2014. Operating results for the nine months ended September 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. These reclassifications have no impact on our previously reported results of operations, balance sheet or cash flows.

Going Concern Presumption and Management’s Plans

These unaudited Condensed Consolidated Financial Statements have been prepared on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities and other commitments in the normal course of business. We have incurred net losses in each of the three years ending December 31, 2014, and reported a net loss attributable to common shareholders of $(129.5) million for the nine months ended September 30, 2015. While we were in compliance with the covenants of our revolving credit agreement (the “Revolver”) as of September 30, 2015, based on our current operating forecast and capital structure, we do not believe we will be able to comply with all of the covenants under the Revolver during the next twelve months. We are also dependent on obtaining additional debt and/or equity financing to continue our planned principal business operations. These factors raise substantial doubt about our ability to continue as a going concern.

Management’s plans in regard to these matters consist principally of restructuring our debt or seeking additional debt or equity funding from outside sources. We are actively working to address these matters, however, there can be no assurance that our efforts will be successful. The Condensed Consolidated Financial Statements do not include any adjustments that may result from the outcome of this uncertainty.

Our primary sources of liquidity include cash from operating activities, borrowings under the Revolver, proceeds from the sales of assets and, from time to time, proceeds from capital market transactions, including the offering 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. Due primarily to the substantial decline in commodity prices over the last twelve months, our liquidity has been adversely impacted. We have taken several actions thus far and are in the process of pursuing others in order to enhance our liquidity, de-lever our balance sheet and mitigate the impact of lower commodity prices on our operations, as follows:

• We reduced the number of contracted drilling rigs operating in the Eagle Ford to one in August 2015 and negotiated certain completion services for lower costs through an extended period (see Note 12). We also adjusted our drilling and well stimulation design resulting in lower overall drilling and completion costs.

• We sold all of our assets in East Texas for net proceeds of approximately $73 million in August 2015 (see Note 3).

• We suspended the payment of dividends on our convertible preferred stock in September 2015 (see Note 13).

• We sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for net proceeds of approximately $13 million in October 2015 (see Note 3).

• We reduced our employee headcount by approximately 16 percent from year-end 2014 levels through administrative and operations restructuring initiatives taken in May and October 2015.

• We engaged Jefferies LLC (“Jefferies”) to advise us with respect to asset-level financing transactions and various financing and debt restructuring options (see Note 12).

While we have substantially reduced our capital expenditures program, we will be challenged in the first half of 2016 to maintain our currently contemplated drilling program as anticipated receipts from our derivative portfolio will decline as existing hedges expire and significant interest payment requirements on our senior subordinated notes become due in April and May of 2016. Moreover, unless we can access additional capital, we will likely be forced to further curtail or suspend our currently contemplated drilling program in 2016.

Without a refinancing or some restructuring of our debt obligations, we anticipate that we will exceed the debt leverage covenant under the Revolver at the end of the first quarter of 2016. We could request a waiver of this covenant or we could refinance the Revolver; however, there is no assurance that the bank lenders will grant such a waiver or that we could refinance the Revolver on acceptable terms or at all. If no waiver were granted, we would be in default under the Revolver and, if such default were not waived, all amounts outstanding under the Revolver and our senior notes would need to be immediately repaid. The obligation to repay all such amounts could force us to seek bankruptcy protection.

Consequently, as noted above, we are currently working with Jefferies to pursue a number of strategic financing and debt restructuring alternatives, including, but not limited to, debt and equity financing and joint venture financing, among others. There can be no assurance that any of these alternatives will be successful on acceptable terms or at all.

New Accounting Pronouncements

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015–03”) on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10) as clarified by ASU 2015–15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements–Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (“ASU 2015–15”).

In 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. In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, that defers by one year the effective date of ASU 2014–09 to fiscal years beginning after December 17, 2017, or calendar year 2018 for us. 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.

Subsequent Events

Management has evaluated all activities of the Company through the date upon which our Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of non-core properties in the southwestern portion of our Eagle Ford acreage referenced above and in Note 3, 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 asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes of recognizing and measuring asset impairments include, but are not limited to, estimates of proved and probable reserves, future commodity prices, 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	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash flows from operating activities
Net income (loss)	$ (111,394)	$ 8,102
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	253,056	215,623
Impairments	1,084	123,992
Accretion of firm transportation obligation	705	991
Derivative contracts:
Net gains	(52,073)	(8,130)
Cash settlements, net	104,590	(17,836)
Deferred income tax expense (benefit)	266	(339)
Gain on sales of assets, net	(50,803)	(120,295)
Non-cash exploration expense	4,903	8,387
Non-cash interest expense	3,504	3,114
Share-based compensation (equity-classified)	3,369	2,638
Other, net	(17)	325
Changes in operating assets and liabilities, net	5,051	(16,122)
Net cash provided by operating activities	162,241	200,450
Cash flows from investing activities
Receipts to settle working capital adjustments assumed in acquisition, net	0	33,712
Capital expenditures – property and equipment	(324,876)	(545,031)
Proceeds from sales of assets, net	73,670	311,913
Net cash used in investing activities	(251,206)	(199,406)
Cash flows from financing activities
Proceeds from issuance of preferred stock, net	0	313,330
Payments made to induce conversion of preferred stock	0	(4,256)
Proceeds from revolving credit facility borrowings	203,000	377,000
Repayment of revolving credit facility borrowings	(98,000)	(583,000)
Debt issuance costs paid	(744)	(151)
Dividends paid on preferred stock	(18,201)	(5,165)
Other, net	0	1,414
Net cash provided by financing activities	86,055	99,172
Net (decrease) increase in cash and cash equivalents	(2,910)	100,216
Cash and cash equivalents – beginning of period	6,252	23,474
Cash and cash equivalents – end of period	3,342	123,690
Cash paid for:
Interest	47,489	47,778
Income taxes	7	100
Non-cash Investing activities:
Changes in accrued liabilities related to capital expenditures	$ (41,800)	$ 12,805

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CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 25,900	$ 89,661	$ (111,394)	$ 8,102
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax of $(6) and $(17) in 2015 and $14 and $40 in 2014	(11)	25	(32)	74
Total Other Comprehensive Income (Loss), Net of Tax	(11)	25	(32)	74
Comprehensive income (loss)	$ 25,889	$ 89,686	$ (111,426)	$ 8,176

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Additional Balance Sheet Detail

9 Months Ended

Sep. 30, 2015

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,
	2015		2014
Other current assets:
Tubular inventory and well materials	$	2,925	$	5,802
Prepaid expenses	3,614		4,215
Other	763		97
	$	7,302	$	10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	$	4,014	$	4,123
Deferred issuance costs of the Revolver	1,796		1,623
Other	26		95
	$	5,836	$	5,841
Accounts payable and accrued liabilities:
Trade accounts payable	$	24,768	$	122,994
Drilling and other lease operating costs	26,643		68,842
Royalties and revenue – related	52,062		78,359
Compensation – related	12,853		9,197
Interest	37,438		15,555
Preferred stock dividends	—		6,067
Other	8,144		11,213
	$	161,908	$	312,227
Other liabilities:
Deferred gains on sales of assets	$	82,944	$	90,569
Firm transportation obligation	11,068		12,042
Asset retirement obligations	2,570		5,889
Defined benefit pension obligations	1,508		1,753
Postretirement health care benefit obligations	965		890
Compensation – related	1,150		7,631
Deferred compensation – SERP obligations and other	4,020		4,183
Other	1,012		929
	$	105,237	$	123,886

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Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Nov. 06, 2015
Document Documentand Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2015
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	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		73,357,172

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Fair Value Measurements

9 Months Ended

Sep. 30, 2015

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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, 2015, 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, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	68,272	$	300,000	$	234,000	$	300,000
Senior Notes due 2020	197,675		775,000		620,000		775,000
	$	265,947	$	1,075,000	$	854,000	$	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, 2015
	Fair Value		Fair Value Measurement Classification
Description	Measurement		Level 1		Level 2		Level 3
Assets:
Commodity derivative assets – current	$	96,211	$	—	$	96,211	$	—
Commodity derivative assets – noncurrent	16,149		—		16,149		—
Assets of SERP	4,014		4,014		—		—
Liabilities:
Deferred compensation – SERP obligations	4,019		4,019		—		—

	As of December 31, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	128,981		$	—		$	128,981	$	—
Commodity derivative assets – noncurrent	35,897			—			35,897		—
Assets of SERP	4,123			4,123			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,178		)	(4,178		)	—		—

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, 2015 and 2014.

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 asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes of recognizing and measuring asset impairments include, but are not limited to, estimates of proved and probable reserves, future commodity prices, 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 COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Statement of Comprehensive Income [Abstract]
Change in pension and postretirement obligations, net of tax	$ (6)	$ 14	$ (17)	$ 40

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Derivative Instruments

9 Months Ended

Sep. 30, 2015

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. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We utilize collars and swaps, 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.

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, 2015:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2015 1	Collars	3,000	$	86.67	$	94.73	$	6,817	$	—
Fourth quarter 2015 1	Swaps	8,000	$	91.06			26,603		—
First quarter 2016	Swaps	6,000	$	80.41			17,903		—
Second quarter 2016	Swaps	6,000	$	80.41			17,154		—
Third quarter 2016	Swaps	6,000	$	80.41			16,764		—
Fourth quarter 2016	Swaps	6,000	$	80.41			16,150		—
Settlements to be received in subsequent period							10,970		—

_______________________

¹ Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI crude oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the fourth quarter of 2015.

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,
	2015		2014			2015			2014
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	32,258	$	(7,557	)	$	104,590		$	(17,836	)
Gains (losses) attributable to:
Commodity contracts	12,443		74,014			(52,517		)	25,966
	$	44,701	$	66,457		$	52,073		$	8,130

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, 2015				December 31, 2014
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	96,211	$	—	$	128,981	$	—
Commodity contracts	Derivative assets/liabilities – noncurrent	16,149		—		35,897		—
		$	112,360	$	—	$	164,878	$	—

As of September 30, 2015, we reported a commodity derivative asset of $112.4 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with four 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, 2015

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,
	2015			2014
Customers	$	37,010		$	62,650
Joint interest partners	29,693			120,708
Other	7,872			6,549
	74,575			189,907
Less: Allowance for doubtful accounts	(1,555		)	(280		)
	$	73,020		$	189,627

For the nine months ended September 30, 2015, two customers accounted for $108.4 million, or approximately 50%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2015 were $62.3 million and $46.1 million, or 29% and 21% of the consolidated total, respectively. As of September 30, 2015, $16.5 million, or approximately 45% of our consolidated accounts receivable from customers, was related to these customers.

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, $55.7 million and $52.6 million, or approximately 21%, 18%, 13% and 13% of the consolidated total. As of December 31, 2014, $39.3 million, or approximately 63% 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, 2015

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,
	2015			2014			2015			2014
Net income (loss)	$	25,900		$	89,661		$	(111,394	)	$	8,102
Less: Preferred stock dividends	(5,935		)	(7,641		)	(18,069		)	(11,081		)
Less: Induced conversion of preferred stock	—			(888		)	—			(4,256		)
Net income (loss) attributable to common shareholders – basic	$	19,965		$	81,132		$	(129,463	)	$	(7,235	)
Add: Preferred stock dividends 1	5,935			7,641			—			—
Add: Induced conversion of preferred stock 1	—			888			—			—
Net income (loss) attributable to common shareholders – diluted	$	25,900		$	89,661		$	(129,463	)	$	(7,235	)
Weighted-average shares – basic	72,651			71,536			72,438			67,909
Effect of dilutive securities 2	30,801			32,070			—			—
Weighted-average shares – diluted	103,452			103,606			72,438			67,909

_______________________

1 Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the nine months ended September 30, 2015 and 2014, approximately 31.1 millionand24.9 million, respectively, of 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.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Drilling and Completion Commitments

As of September 30, 2015, we had a contractual commitment for one drilling rig with a term expiring in February 2016. The minimum commitment under this agreement is $2.4 million for the fourth quarter of 2015 and $0.8 million in 2016. In September 2015, we renegotiated an existing commitment to purchase certain coil tubing services at a lower rate and extended the expiration from December 31, 2015 to June 30, 2016. The minimum commitment remaining under this agreement is $1.0 million. The drilling rig and coil tubing services 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 the penalty is based on the number of days remaining in the contractual term. The penalty amount would have been $3.4 million had we terminated those agreements on September 30, 2015.

In 2015, we reduced our total drilling rig count from eight to one. We incurred a total of $6.2 million in early termination charges with respect to these terminations in the nine months ended September 30, 2015, which have been reported as a component of Exploration expense on our Condensed Consolidated Statements of Operations.

Firm Transportation Commitments

We have entered into contracts for firm transportation capacity rights for specified daily volumes on various pipeline systems with remaining terms that range from less than one to 13 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. The minimum commitment under these agreements is $0.5 million for the fourth quarter of 2015 and approximately $1.1 million per year through 2028. We may sell excess capacity to third parties at our discretion.

Gathering and Intermediate Transportation Commitments

We have a long-term agreement for 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 payments regardless of the volume of natural gas production for the first three years of the term. The minimum fee requirement remaining under this agreement is $1.1 million for the fourth quarter of 2015 and $5.0 million in 2016.

We also have long-term agreements for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our payment obligations with respect to these services will begin when construction of the gathering and transportation system is completed, which is expected to be in the first quarter of 2016. The agreements also 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 approximately $12.3 million on an annual basis.

Financial Advisory Commitment

In July 2015, we retained Jefferies to provide financial advice generally and to act as our exclusive financial advisor in connection with asset-level financing transactions with investors related to our Eagle Ford assets, including joint venture arrangement transactions. In connection with this engagement, Jefferies is also advising us with respect to various financing and debt restructuring options. In addition to certain cash-based fees in connection with these services, we have agreed to pay Jefferies an advisory fee of 6.5 million shares of our common stock payable upon the closing of an asset-level financing transaction.

Other Commitments

In connection with our August 2014 acquisition of undeveloped acreage in the Eagle Ford in Lavaca County, Texas, we committed to providing a drilling carry in the amount of $10.7 million to support development of this acreage through July 2017. If we have not incurred the full balance of the drilling carry by the third anniversary date of the transaction, we will be required to make a cash payment to the seller to satisfy any shortfall.

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 that remained outstanding as of September 30, 2015. As of September 30, 2015, we also had AROs of approximately $2.6 million attributable to the plugging of abandoned wells.

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Income Taxes

9 Months Ended

Sep. 30, 2015

Income Tax Disclosure [Abstract]

Income Tax Disclosure [Text Block]

Income Taxes

We recognized a federal income tax benefit for the three and nine months ended September 30, 2015 at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of recent cumulative losses. The income tax provision includes a benefit of $0.7 million attributable to a federal return to provision adjustment and a minimal deferred state income tax expense of $0.3 million resulting in a combined effective tax rate of 0.4% for the nine months ended September 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.4% is due primarily to the valuation allowance placed against our deferred tax assets.

We recognized an income tax benefit for nine months ended September 30, 2014 at an effective rate of 4.4% which reflects the adverse effects of losses incurred in jurisdictions for which we may not realize a tax benefit and therefore recorded a valuation allowance against the related deferred tax assets.

We paid state income taxes of less than $0.1 million during the nine months ended September 30, 2015 and $0.1 million during the nine months ended September 30, 2014. In October 2015, we received a federal income tax refund of $0.7 million which, as of September 30, 2015, is included as a component of Other current assets on our Condensed Consolidated Balance Sheets.

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Property and Equipment

9 Months Ended

Sep. 30, 2015

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,
	2015			2014
Oil and gas properties:
Proved	$	2,687,598		$	3,390,482
Unproved	125,571			125,676
Total oil and gas properties	2,813,169			3,516,158
Other property and equipment	31,423			75,073
Total properties and equipment	2,844,592			3,591,231
Accumulated depreciation, depletion and amortization	(1,026,006		)	(1,766,133		)
	$	1,818,586		$	1,825,098

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Long-Term Debt

9 Months Ended

Sep. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

The following table summarizes our long-term debt as of the dates presented giving effect to the adoption of ASU 2015–03:

	As of
	September 30, 2015				December 31, 2014
	Principal		Unamortized Issuance Costs		Principal		Unamortized Issuance Costs
Revolving credit facility 1	$	140,000			$	35,000
Senior notes due 2019	300,000		$	3,510	300,000		$	4,131
Senior notes due 2020	775,000		18,128		775,000		20,440
Totals	1,215,000		$	21,638	1,110,000		$	24,571
Long-term debt, net of unamortized issuance costs	$	1,193,362			$	1,085,429

_______________________

¹ Issuance costs attributable to the Revolver, which represent costs attributable to the access to credit over the Revolver’s contractual term, are presented as a component of Other assets (see Note 10) in accordance with ASU 2015-15.

Revolving Credit Facility

Subsequent to the sale of our East Texas assets in August 2015, the commitment and borrowing base under the Revolver were reduced to $395 million from $425 million. In addition to the outstanding borrowings, we had letters of credit of $1.8 million outstanding as of September 30, 2015. As of September 30, 2015, our available borrowing capacity under the Revolver was $253.2 million.

In November 2015 in connection with the semi-annual redetermination, our lenders decreased their aggregate total commitment and borrowing base under the Revolver to $275 million due primarily to depressed commodity prices and our reduced capital program. The Revolver 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. The next semi-annual redetermination is scheduled for May 2016. Revolver borrowings may be used for general purposes, including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017.

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, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 2.0000%, which is derived from an Adjusted LIBOR rate of 0.2500% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2015, 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.

In order to borrow under the Revolver, we must make certain representations and warranties to our bank lenders at the time of each borrowing, including a representation relating to our solvency. If we are unable to make these representations and warranties, we would be unable to borrow under the Revolver, absent a waiver. We will not be able to give the solvency representation if at the time we desire to make a future borrowing we are unable to determine that the fair market value of our assets exceeds the face amount of our liabilities.

The Revolver includes current ratio, leverage ratio and credit exposure financial covenants. Under the current ratio covenant, the ratio of current assets to current liabilities as of the last day of any fiscal quarter may not be less than 1.0 to 1.0. 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. Under the leverage ratio covenant, the ratio of total debt to EBITDAX, for any four consecutive quarters may not exceed 4.75 to 1.0 through March 31, 2016; 5.25 to 1.0 through June 30, 2016; 5.50 to 1.0 through December 31, 2016; 4.50 to 1.0 through March 31, 2017; and 4.0 to 1.0 through maturity in September 2017. Furthermore, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if the leverage ratio for the preceding four quarters exceeds 5.0 to 1.0. Under the credit exposure covenant, the ratio of credit exposure to EBITDAX, for any four consecutive quarters ending on or prior to March 31, 2017 may not exceed 2.75 to 1.0. Credit exposure consists of all outstanding borrowings under the Revolver, including any outstanding letters of credit.

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% which is payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in April 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 8.50% 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.50% which is payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. 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.

Guarantees

The guarantees 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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Firm Transportation Obligation

9 Months Ended

Sep. 30, 2015

Restructuring and Related Activities [Abstract]

Restructuring and Exit Activities

Firm Transportation Obligation

We have a contractual obligation 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 following table reconciles the obligation as of the dates presented:

	As of
	September 30,			December 31,
	2015			2014
Balance at beginning of period	$	14,790		$	15,993
Accretion	705			1,301
Cash payments, net	(1,691		)	(2,504		)
Balance at end of period	$	13,804		$	14,790

The accretion of the obligation, net of any recoveries from periodic sales of our contractual capacity, is charged as an offset to Other revenue. As of September 30, 2015, $2.8 million of the obligation is classified as current and is included in the Accounts payable and accrued liabilities caption while the remaining $11.0 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.

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Interest Expense (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015			2014			2015			2014
Interest on borrowings and related fees	$	23,239		$	22,559		$	69,371		$	69,477
Amortization of debt issuance costs	1,224			1,063			3,504			3,114
Capitalized interest	(1,478		)	(1,669		)	(4,854		)	(4,875		)
	$	22,985		$	21,953		$	68,021		$	67,716

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Fair Value Summary of Long-Term Debt with Fixed Interest Rates (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	$ 265,947	$ 854,000
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	68,272	234,000
Fair Value | 8.50% Senior Notes due 2020
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt with fixed interest rates	197,675	620,000
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 | 8.50% 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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Share-Based Compensation

9 Months Ended

Sep. 30, 2015

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 the 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 the 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,
	2015			2014			2015			2014
Equity-classified awards:
Stock option awards	$	462		$	403		$	1,242		$	1,193
Common, deferred and restricted stock and stock unit awards	801			584			2,127			1,445
	1,263			987			3,369			2,638
Liability-classified awards	(851		)	(360		)	(686		)	6,632
	$	412		$	627		$	2,683		$	9,270

In February 2015, we paid $1.5 million in cash pursuant to the terms of PBRSU grants made in 2012.

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Commodity Derivative Positions

The following table sets forth our commodity derivative positions as of September 30, 2015:

		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2015 1	Collars	3,000	$	86.67	$	94.73	$	6,817	$	—
Fourth quarter 2015 1	Swaps	8,000	$	91.06			26,603		—
First quarter 2016	Swaps	6,000	$	80.41			17,903		—
Second quarter 2016	Swaps	6,000	$	80.41			17,154		—
Third quarter 2016	Swaps	6,000	$	80.41			16,764		—
Fourth quarter 2016	Swaps	6,000	$	80.41			16,150		—
Settlements to be received in subsequent period							10,970		—

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,
	2015		2014			2015			2014
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	32,258	$	(7,557	)	$	104,590		$	(17,836	)
Gains (losses) attributable to:
Commodity contracts	12,443		74,014			(52,517		)	25,966
	$	44,701	$	66,457		$	52,073		$	8,130

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, 2015				December 31, 2014
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	96,211	$	—	$	128,981	$	—
Commodity contracts	Derivative assets/liabilities – noncurrent	16,149		—		35,897		—
		$	112,360	$	—	$	164,878	$	—

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Summary of Firm Transportation Obligation (Detail) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Firm Transportation Obligation [Roll Forward]
Balance at beginning of period	$ 14,790	$ 15,993	$ 15,993
Accretion	705	$ 991	1,301
Cash payments, net	(1,691)		(2,504)
Balance at end of period	$ 13,804		$ 14,790

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Commodity Derivative Positions (Detail) $ in Thousands	3 Months Ended
	Sep. 30, 2015 USD ($) bbl $ / bbl $ / bbl
Settlements to be received in subsequent period
Derivative Instruments Related to Oil and Gas Production [Line Items]
Fair Value Asset	$ 10,970
Fair Value Liability	$ 0
Crude Oil | Fourth quarter 2015
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Collars
Notional Volume, per day | bbl	3,000
Weighted Average Price, Floor/Swap | $ / bbl	86.67
Weighted Average Price, Ceiling | $ / bbl	94.73
Fair Value Asset	$ 6,817
Fair Value Liability	$ 0
Crude Oil | Third and fourth quarters 2015 | Short Put
Derivative Instruments Related to Oil and Gas Production [Line Items]
Strike price on put options | $ / bbl	70.00
Notional Volume, per day | bbl	5,000
Crude Oil | Fourth quarter 2015
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	8,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	91.06
Fair Value Asset	$ 26,603
Fair Value Liability	$ 0
Crude Oil | First quarter 2016
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	80.41
Fair Value Asset	$ 17,903
Fair Value Liability	$ 0
Crude Oil | Second quarter 2016
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	80.41
Fair Value Asset	$ 17,154
Fair Value Liability	$ 0
Crude Oil | Third quarter 2016
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	80.41
Fair Value Asset	$ 16,764
Fair Value Liability	$ 0
Crude Oil | Fourth quarter 2016
Derivative Instruments Related to Oil and Gas Production [Line Items]
Instrument	Swaps
Notional Volume, per day | bbl	6,000
Derivative, Swap Type, Average Fixed Price | $ / bbl	80.41
Fair Value Asset	$ 16,150
Fair Value Liability	$ 0

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CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Current assets
Cash and cash equivalents	$ 3,342	$ 6,252
Accounts receivable, net of allowance for doubtful accounts	73,020	189,627
Derivative assets	96,211	128,981
Deferred income taxes	0	53
Other current assets	7,302	10,114
Total current assets	179,875	335,027
Property and equipment, net (successful efforts method)	1,818,586	1,825,098
Derivative assets	16,149	35,897
Other assets	5,836	5,841
Total assets	2,020,446	2,201,863
Current liabilities
Accounts payable and accrued liabilities	161,908	312,227
Derivative liabilities	0	0
Total current liabilities	161,908	312,227
Other liabilities	105,237	123,886
Deferred income taxes	4,868	4,504
Long-term debt, net of unamortized issuance costs	$ 1,193,362	$ 1,085,429
Commitments and contingencies (Note 12)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,070 shares and 7,945 shares issued as of September 30, 2015 and December 31, 2014, respectively, and Series B – 32,500 shares issued as of September 30, 2015 and December 31, 2014, each with a redemption value of $10,000 per share	$ 3,957	$ 4,044
Common stock of $0.01 par value – 228,000,000 shares authorized; 73,297,205 and 71,568,936 shares issued as of September 30, 2015 and December 31, 2014, respectively	548	529
Paid-in capital	1,209,187	1,206,305
Accumulated deficit	(658,704)	(535,176)
Deferred compensation obligation	3,440	3,211
Accumulated other comprehensive income	217	249
Treasury stock – 455,689 and 262,070 shares of common stock, at cost, as of September 30, 2015 and December 31, 2014, respectively	(3,574)	(3,345)
Total shareholders’ equity	555,071	675,817
Total liabilities and shareholders’ equity	$ 2,020,446	$ 2,201,863

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Divestitures

9 Months Ended

Sep. 30, 2015

Acquisitions and Divestitures [Abstract]

Acquisitions and Divestitures

Divestitures

East Texas and Other Properties

In August 2015, we sold our East Texas assets and received cash proceeds of approximately $73 million, net of transaction costs and customary closing adjustments. The effective date of the sale was May 1, 2015 and we recognized a gain of approximately $43 million. The carrying value of the net assets disposed in this transaction was $28.5 million, including oil and gas properties and other fixed assets of $32.3 million, net of related asset retirement obligations (“AROs”) of $3.8 million. The net pre-tax operating income (loss) attributable to the East Texas assets was $1.0 million and $(6.9) million for the three months ended September 30, 2015 and 2014 and $1.7 million and $(18.4) million for the nine months ended September 30, 2015 and 2014. The net proceeds from this transactions were used to pay down a portion of our outstanding borrowings under the Revolver.

In October 2015, we also sold certain non-core properties in the southwestern portion of our Eagle Ford acreage for approximately $13 million, net of transaction costs and customary closing adjustments. We expect to recognize a loss of approximately $9 million on this transaction in the fourth quarter of 2015.

Oil Gathering System Construction Rights

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 approximately $147 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate transportation services for a substantial portion of our 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 to be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be in the first quarter of 2016. In September 2015, the gathering agreement with Republic was amended to reduce the number of wells initially required to be connected to the pipeline system, provide for alternative transportation in areas that will not be served by the pipeline and also reduce the gathering fees. As a result of the amendment, we recognized $8.4 million of deferred gain in September 2015. As of September 30, 2015, $2.3 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $73.5 million, representing the remaining noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

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 (“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 $0.3 million of the deferred gain during each of the nine months ended September 30, 2015 and 2014. As of September 30, 2015, $0.4 million of the remaining deferred gain was included as a component of Accounts payable and accrued expenses and $9.5 million, representing the noncurrent portion, was included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

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Components of Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended			9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014	Sep. 30, 2015		Sep. 30, 2014
Earnings Per Share [Abstract]
Net income (loss)		$ 25,900		$ 89,661	$ (111,394)		$ 8,102
Less: Preferred stock dividends	[1]	(5,935)		(7,641)	(18,069)		(11,081)
Less: Induced conversion of preferred stock		0		(888)	0		(4,256)
Net income (loss) attributable to common shareholders, Basic		19,965		81,132	(129,463)		(7,235)
Add: Preferred stock dividends		5,935	[1]	7,641	0	[1]	0
Add: Induced conversion of preferred stock 1		0		888	0		0
Net loss attributable to common shareholders, Diluted		$ 25,900		$ 89,661	$ (129,463)		$ (7,235)
Weighted-average shares – basic		72,651		71,536	72,438		67,909
Effect of dilutive securities	[2]	30,801		32,070	0		0
Weighted-average shares – diluted		103,452		103,606	72,438		67,909
Potentially dilutive securities with the effect of being anti-dilutive excluded from the calculation of diluted earnings per common share					31,100		24,900

[1] Preferred stock dividends and payments to induce the conversion of preferred stock were excluded from the computation of diluted earnings per share for the nine months ended September 30, 2015 and 2014 as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

[2] For the nine months ended September 30, 2015 and 2014, approximately 31.1 million and 24.9 million, respectively, of 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.

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Property and Equipment (Tables)

9 Months Ended

Sep. 30, 2015

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,
	2015			2014
Oil and gas properties:
Proved	$	2,687,598		$	3,390,482
Unproved	125,571			125,676
Total oil and gas properties	2,813,169			3,516,158
Other property and equipment	31,423			75,073
Total properties and equipment	2,844,592			3,591,231
Accumulated depreciation, depletion and amortization	(1,026,006		)	(1,766,133		)
	$	1,818,586		$	1,825,098

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Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Receivables [Abstract]
Customers	$ 37,010	$ 62,650
Joint interest partners	29,693	120,708
Other	7,872	6,549
Accounts Receivable, Gross, Current, Total	74,575	189,907
Less: Allowance for doubtful accounts	(1,555)	(280)
Accounts receivable, net of allowance for doubtful accounts	$ 73,020	$ 189,627

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Shareholders' Equity

9 Months Ended

Sep. 30, 2015

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, 2015 and 2014:

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			September 30,
	2014			Net Loss			Offering		Declared 1			Changes 2			2015
Preferred stock 3	$	4,044		$	—		$	—	$	—		$	(87	)	$	3,957
Common stock 3	529			—			—		—			19			548
Paid-in capital 3	1,206,305			—			—		—			2,882			1,209,187
Accumulated deficit	(535,176		)	(111,394		)	—		(12,134		)	—			(658,704		)
Deferred compensation obligation	3,211			—			—		—			229			3,440
Accumulated other comprehensive income 4	249			—			—		—			(32		)	217
Treasury stock	(3,345		)	—			—		—			(229		)	(3,574		)
	$	675,817		$	(111,394	)	$	—	$	(12,134	)	$	2,782		$	555,071
	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

_______________________

¹ Includes dividends declared of $300.00 per share and $450.00 per share of our Series A 6% Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the nine months ended September 30, 2015 and 2014, respectively, and $300.00 per share and $198.33 per share of our Series B 6% Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the nine months ended September 30, 2015 and 2014, respectively.

² Includes equity-classified share-based compensation of $3,369 and $2,638 for the nine months ended September 30, 2015 and 2014, respectively.

³ A total of 875 shares, or 87,500 depositary shares, of the Series A Preferred Stock were converted into 1,458,336 shares of our common stock during the nine months ended September 30, 2015. 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 during the 2014 period.

⁴ 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, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(49) and $114 and are presented above net of taxes of $(17) and $40, respectively.

In September 2015, we announced a suspension of quarterly dividends on the Series A Preferred Stock and Series B Preferred Stock for the quarter ended September 30, 2015. Our articles of incorporation provide that any unpaid dividends, including the unpaid dividends for the quarter ended September 30, 2015 and any future unpaid dividends, will accumulate. While the accumulation does not result in presentation of a liability on the balance sheet, the accumulated dividends are deducted from our net income (or added to our net loss) in the determination of income (loss) attributable to common shareholders and the related earnings (loss) per share. For the quarter ended September 30, 2015, we accumulated a total of $5.9 million in unpaid preferred stock dividends, including $1.0 million attributable to dividends of $150.00 per share on 7,070 eligible shares of the Series A Preferred Stock and $4.9 million attributable to dividends of $150.00 per share on 32,500 eligible shares of the Series B Preferred Stock.

If we do not pay dividends on our Series A Preferred Stock and B Preferred Stock for six quarterly periods, whether consecutive or non-consecutive, the holders of the shares of both series of preferred stock, voting together as a single class, will have the right to elect two additional directors to serve on our board of directors until all accumulated and unpaid dividends are paid in full.

In May 2015, Penn Virginia’s articles of incorporation were amended to increase the number of total authorized shares of common stock by 100 million to 228 million from 128 million.