BAYTEX ENERGY USA, INC. - Quarter Report: 2015 September (Form 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



¨	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.

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.

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.

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.

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).

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

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.

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.


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.

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.

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.


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.


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


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.

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.

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.


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.


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


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 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.

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.


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.

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

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.

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.

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.

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.

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.

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.

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.

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.

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 costs¹	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.

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

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.

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.

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.

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	)

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.

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

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.

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.

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 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.

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, or 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.

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.

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		—

_______________________

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.

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

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)