BAYTEX ENERGY USA, INC. - Quarter Report: 2013 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, 2013



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

For the transition period from to

Commission file number: 1-13283

_________________________________________________________

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________



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

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

__________________________________________________________

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

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

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



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

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

As of October 25, 2013, 65,292,520 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, 2013

Table of Contents



Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2013 and 2012	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2013 and 2012	4
	Condensed Consolidated Balance Sheets as of September 30, 2013 and December 31, 2012	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2013 and 2012	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Acquisitions and Divestitures	7
	4. Accounts Receivable and Major Customers	9
	5. Derivative Instruments	9
	6. Property and Equipment	12
	7. Long-Term Debt	12
	8. Income Taxes	13
	9. Additional Balance Sheet Detail	13
	10. Fair Value Measurements	15
	11. Commitments and Contingencies	16
	12. Shareholders' Equity	17
	13. Share-Based Compensation	17
	14. Restructuring and Exit Activities	18
	15. Impairments	19
	16. Interest Expense	19
	17. Earnings per Share	20
Forward-Looking Statements		21
2.	Management's Discussion and Analysis of Financial Condition and Results of Operations:
	Overview of Business	22
	Key Developments	22
	Results of Operations	25
	Liquidity and Capital Resources	39
	Environmental Matters	43
	Critical Accounting Estimates	44
	New Accounting Standards	44
3.	Quantitative and Qualitative Disclosures About Market Risk	45
4.	Controls and Procedures	47
Part II - Other Information
6.	Exhibits	48
Signatures		49

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,
	2013			2012			2013			2012
Revenues
Crude oil	$	100,564		$	56,995		$	250,489		$	174,100
Natural gas liquids (NGLs)	8,212			6,671			22,652			23,298
Natural gas	12,872			11,909			40,465			37,098
(Loss) gain on sales of property and equipment, net	(186		)	1,573			(479		)	2,407
Other	151			551			1,339			2,052
Total revenues	121,613			77,699			314,466			238,955
Operating expenses
Lease operating	8,457			6,206			24,891			24,613
Gathering, processing and transportation	3,039			3,127			9,598			11,672
Production and ad valorem taxes	6,597			4,589			19,532			7,915
General and administrative	12,677			11,634			39,276			35,522
Exploration	3,957			9,265			18,097			26,647
Depreciation, depletion and amortization	62,450			49,331			178,355			151,888
Impairments	132,224			700			132,224			29,316
Loss on firm transportation commitment	—			17,332			—			17,332
Total operating expenses	229,401			102,184			421,973			304,905
Operating loss	(107,788		)	(24,485		)	(107,507		)	(65,950		)
Other income (expense)
Interest expense	(20,218		)	(14,979		)	(56,505		)	(44,837		)
Loss on extinguishment of debt	—			(3,144		)	(29,157		)	(3,144		)
Derivatives	(24,035		)	(12,271		)	(23,208		)	31,250
Other	35			60			79			89
Loss from operations before income taxes	(152,006		)	(54,819		)	(216,298		)	(82,592		)
Income tax benefit	53,106			22,208			75,577			32,444
Net loss	(98,900		)	(32,611		)	(140,721		)	(50,148		)
Preferred stock dividends	(1,725		)	—			(5,175		)	—
Net loss attributable to common shareholders	$	(100,625	)	$	(32,611	)	$	(145,896	)	$	(50,148	)
Net loss per share:
Basic	$	(1.54	)	$	(0.71	)	$	(2.38	)	$	(1.09	)
Diluted	$	(1.54	)	$	(0.71	)	$	(2.38	)	$	(1.09	)

Weighted average shares outstanding - basic	65,465			46,050			61,272			46,009
Weighted average shares outstanding - diluted	65,465			46,050			61,272			46,009

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,
	2013			2012			2013			2012
Net loss	$	(98,900	)	$	(32,611	)	$	(140,721	)	$	(50,148	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $10 and $30 in 2013 and $11 and $37 in 2012	18			23			56			69
	18			23			56			69
Comprehensive loss	$	(98,882	)	$	(32,588	)	$	(140,665	)	$	(50,079	)

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,
	2013			2012
Assets
Current assets
Cash and cash equivalents	$	38,321		$	17,650
Accounts receivable, net of allowance for doubtful accounts	147,920			62,978
Derivative assets	4,424			11,292
Other current assets	5,177			4,595
Total current assets	195,842			96,515
Property and equipment, net (successful efforts method)	2,170,122			1,723,359
Derivative assets	1,900			5,181
Other assets	38,572			17,934
Total assets	$	2,406,436		$	1,842,989

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	223,079		$	111,655
Derivative liabilities	15,305			—
Deferred income taxes	574			370
Total current liabilities	238,958			112,025
Other liabilities	32,467			28,901
Derivative liabilities	799			1,421
Deferred income taxes	135,429			210,767
Long-term debt	1,203,000			594,759

Commitments and contingencies (Note 11)

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; 11,500 shares issued as of September 30, 2013 and December 31, 2012 with a redemption value of $10,000 per share	1,150			1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 65,292,520 and 55,117,346 shares issued as of September 30, 2013 and December 31, 2012, respectively	465			364
Paid-in capital	895,450			849,046
Retained earnings (Accumulated deficit)	(100,106		)	45,790
Deferred compensation obligation	2,727			3,111
Accumulated other comprehensive loss	(926		)	(982		)
Treasury stock – 226,237 and 218,320 shares of common stock, at cost, as of September 30, 2013 and December 31, 2012, respectively	(2,977		)	(3,363		)
Total shareholders’ equity	795,783			895,116
Total liabilities and shareholders’ equity	$	2,406,436		$	1,842,989

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,
	2013			2012
Cash flows from operating activities
Net loss	$	(140,721	)	$	(50,148	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on extinguishment of debt	29,157			3,144
Loss on firm transportation commitment	—			17,332
Depreciation, depletion and amortization	178,355			151,888
Impairments	132,224			29,316
Derivative contracts:
Net losses (gains)	23,208			(31,250		)
Cash settlements	1,625			24,189
Deferred income tax benefit	(75,577		)	(32,444		)
Loss (gain) on sales of assets, net	479			(2,407		)
Non-cash exploration expense	14,167			24,765
Non-cash interest expense	2,846			3,107
Share-based compensation (equity-classified)	4,781			4,233
Other, net	1,461			302
Changes in operating assets and liabilities	52,829			48,187
Net cash provided by operating activities	224,834			190,214

Cash flows from investing activities
Acquisition, net	(358,239		)	—
Payments to settle working capital adjustments assumed in acquisition, net	(43,023		)	—
Capital expenditures - property and equipment	(356,964		)	(257,194		)
Proceeds from sales of assets, net	653			93,276
Other, net	—			180
Net cash used in investing activities	(757,573		)	(163,738		)

Cash flows from financing activities
Proceeds from the issuance of senior notes	775,000			—
Retirement of senior notes	(319,090		)	—
Proceeds from revolving credit facility borrowings	219,000			181,000
Repayment of revolving credit facility borrowings	(91,000		)	(203,000		)
Debt issuance costs paid	(25,199		)	(1,779		)
Dividends paid on preferred stock	(5,137		)	—
Dividends paid on common stock	—			(5,176		)
Other, net	(164		)	—
Net cash provided by (used in) financing activities	553,410			(28,955		)
Net increase (decrease) in cash and cash equivalents	20,671			(2,479		)
Cash and cash equivalents - beginning of period	17,650			7,512
Cash and cash equivalents - end of period	$	38,321		$	5,033

Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	20,671		$	27,865
Income taxes (net of refunds received)	$	—		$	(32,574	)
Non-cash investing and financing activities:
Other assets acquired related to acquisition	$	52,794		$	—
Other liabilities assumed related to acquisition	$	63,952		$	—
Common stock transferred as consideration for acquisition	$	42,300		$	—

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, 2013

(in thousands, except per share amounts)


1.	Organization

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


2.	Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2012. Operating results for the nine months ended September 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013. Certain amounts for the 2012 period have been reclassified to conform to the current year presentation.

Effective January 1, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 12. The adoption of ASU 2013-02 did not have a significant impact on our Condensed Consolidated Financial Statements and Notes.

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


3.	Acquisitions and Divestitures

Acquisitions

On April 24, 2013 (the “Date of Acquisition”), we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play (the “Acquisition”) from Magnum Hunter Resources Corporation (“MHR”). The Acquisition was originally valued at $401 million with an effective date of January 1, 2013 (the “Effective Date”). On the Date of Acquisition, we paid approximately $380 million in cash, including approximately $19 million of initial purchase price adjustments related to the period from the Effective Date to the Date of Acquisition utilizing a portion of the proceeds from the private placement of $775 million of 8.5% Senior Notes due 2020 (the “2020 Senior Notes”), and issued to MHR 10 million shares of our common stock (the “Shares”) with a fair value of $4.23 per share. Shortly after the Date of Acquisition, certain of our joint interest partners exercised preferential rights related to the Acquisition. We received approximately $21 million from the exercise of these rights, which was recorded as a decrease to our purchase price for the Acquisition.

We incurred $2.4 million of transaction costs associated with the Acquisition, including advisory, legal, due diligence and other professional fees. These costs, as well as fees that we paid to MHR for certain transition services, have been included in the General and administrative caption on our Condensed Consolidated Statements of Operations.

We accounted for the Acquisition by applying the acquisition method of accounting as of the Date of Acquisition. The initial accounting for the Acquisition as presented below is based upon preliminary information and was not complete as of the date our Condensed Consolidated Financial Statements were issued. We received a proposed final settlement from MHR on August 23, 2013. We completed an audit of the settlement statement and submitted our proposed adjustments on October 21, 2013. MHR has 30 days to review and respond to our proposed adjustments. Accordingly, final accounting for the acquired net assets is expected to be completed during the fourth quarter of 2013.

In the three months ended September 30, 2013, we recorded certain measurement period adjustments based on the receipt of additional information which had the effect of increasing the fair value of oil and gas properties by $5.4 million and other assets by $2.0 million with a corresponding increase to accounts payable and accrued expenses of $7.4 million. Accordingly, we have updated the preliminary fair values of net assets acquired from those that were disclosed in our Quarterly Report on Form 10-Q for the period ended June 30, 2013. The following table represents the preliminary fair values assigned to the net assets acquired as of the Date of Acquisition and the consideration transferred:



Assets
Oil and gas properties - proved	$	287,465
Oil and gas properties - unproved	124,232
Accounts receivable, net	50,726
Other assets	2,068
	464,491
Liabilities
Accounts payable and accrued expenses	(62,452		)
Other liabilities	(1,500		)
	(63,952		)
Net assets acquired	$	400,539

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

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

The results of operations attributable to the Acquisition have been included in our Condensed Consolidated Financial Statements from the Date of Acquisition. The following table presents unaudited summary pro forma financial information for the periods presented assuming the Acquisition and the related financing occurred as of January 1, 2012. The pro forma financial information does not purport to represent what our results of operations would have been if the Acquisition had occurred as of this date or the results of operations for any future periods.



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Total revenues	$	121,613		$	97,030		$	340,809		$	288,282
Net loss attributable to common shareholders	$	(99,190	)	$	(30,360	)	$	(139,181	)	$	(28,405	)
Loss per share - basic and diluted	$	(1.52	)	$	(0.54	)	$	(2.13	)	$	(0.51	)

Divestitures

In July 2012, we sold our natural gas assets in West Virginia, Kentucky and Virginia for approximately $100 million. During the three months ended June 30, 2012, we recognized an impairment of $28.6 million related to these assets in advance of the sale, and we recognized a gain of $1.7 million upon completion of the sale during the three months ended September 30, 2012.

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,
	2013			2012
Customers	$	84,412		$	43,967
Joint interest partners	62,588			16,154
Other	1,542			4,523
	148,542			64,644
Less: Allowance for doubtful accounts	(622		)	(1,666		)
	$	147,920		$	62,978

For the nine months ended September 30, 2013, three customers accounted for $124.1 million, or approximately 40%, of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2013 were $51.9 million, $37.7 million and $34.5 million or 17%, 12% and 11% of the consolidated total, respectively. As of September 30, 2013, $46.1 million, or approximately 55% of our consolidated accounts receivable from customers was related to these customers. For the nine months ended September 30, 2012, three customers accounted for $115.6 million, or approximately 49% of our consolidated product revenues. The revenues generated from these customers during the nine months ended September 30, 2012 were $45.9 million, $39.5 million and $30.3 million or approximately 19%, 17% and 13% of the consolidated total, respectively. As of December 31, 2012, $16.3 million, or approximately 37% of our consolidated accounts receivable from customers was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.


5.	Derivative Instruments

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

Commodity Derivatives

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

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

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

The following table sets forth our commodity derivative positions as of September 30, 2013:



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2013	Collars	2,400	$	91.04	$	100.02	$	—	$	707
First quarter 2014	Collars	1,500	$	93.33	102.80		112		154
Second quarter 2014	Collars	1,500	$	93.33	102.80		287		67
Fourth quarter 2013	Swaps	7,000	$	95.94			224		3,806
First quarter 2014	Swaps	7,500	$	93.86			292		3,580
Second quarter 2014	Swaps	7,500	$	93.86			767		2,363
Third quarter 2014	Swaps	8,000	$	93.18			1,041		1,841
Fourth quarter 2014	Swaps	8,000	$	93.18			1,434		1,052
First quarter 2015	Swaps	2,000	$	92.03			192		231
Second quarter 2015	Swaps	2,000	$	92.03			518		376
Third quarter 2015	Swaps	1,000	$	91.25			319		236
Fourth quarter 2015	Swaps	1,000	$	91.25			395		254
First quarter 2014	Swaption	812	$	100.00			—		111
Second quarter 2014	Swaption	812	$	100.00			—		111
Third quarter 2014	Swaption	812	$	100.00			—		112
Fourth quarter 2014	Swaption	812	$	100.00			—		112

Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2013	Collars	15,000	$	3.67	$	4.37	242		—
First quarter 2014	Collars	5,000	$	4.00	$	4.50	131		—
Fourth quarter 2013	Swaps	10,000	$	4.04			411		—
First quarter 2014	Swaps	10,000	$	4.28			407		—
Second quarter 2014	Swaps	15,000	$	4.10			433		—
Third quarter 2014	Swaps	15,000	$	4.10			344		—
Fourth quarter 2014	Swaps	5,000	$	4.50			240		—
First quarter 2015	Swaps	5,000	$	4.50			151		—
Settlements to be paid in subsequent period							—		2,608

Interest Rate Swaps

In February 2012, we entered into an interest rate swap agreement to establish variable interest rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds. As of September 30, 2013, we had no interest rate derivative instruments outstanding.

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,
	2013			2012			2013			2012
Impact by contract type:
Commodity contracts	$	(24,035	)	$	(12,271	)	$	(23,208	)	$	29,844
Interest rate contracts	—			—			—			1,406
	$	(24,035	)	$	(12,271	)	$	(23,208	)	$	31,250
Cash settlements and gains (losses):
Cash received for:
Commodity contract settlements	$	(4,165	)	$	9,238		$	1,625		$	22,783
Interest rate contract settlements	—			—			—			1,406
	(4,165		)	9,238			1,625			24,189
Gains (losses) attributable to:
Commodity contracts	(19,870		)	(21,509		)	(24,833		)	7,061
Interest rate contracts	—			—			—			—
	(19,870		)	(21,509		)	(24,833		)	7,061
	$	(24,035	)	$	(12,271	)	$	(23,208	)	$	31,250

The effects of derivative gains and losses and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net loss to net cash provided by operating activities. These items are recorded in the Derivative contracts section of our Condensed Consolidated Statements of Cash Flows under the Net gains and Cash settlements 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, 2013				December 31, 2012
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	4,424	$	15,305	$	11,292	$	—
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		4,424		15,305		11,292		—

Commodity contracts	Derivative assets/liabilities - noncurrent	1,900		799		5,181		1,421
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		1,900		799		5,181		1,421
		$	6,324	$	16,104	$	16,473	$	1,421

As of September 30, 2013, we reported a commodity derivative asset of $6.3 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have 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,
	2013			2012
Oil and gas properties:
Proved	$	2,791,757		$	2,277,811
Unproved	154,174			60,746
Total oil and gas properties	2,945,931			2,338,557
Other property and equipment	102,998			93,648
Total property and equipment	3,048,929			2,432,205
Accumulated depreciation, depletion and amortization	(878,807		)	(708,846		)
	$	2,170,122		$	1,723,359


7.	Long-Term Debt

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



	As of
	September 30,		December 31,
	2013		2012
Revolving credit facility	$	128,000	$	—
Senior notes due 2016, net of discount (principal amount of $300,000)	—		294,759
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		—
	$	1,203,000	$	594,759

Revolving Credit Facility

The revolving credit facility (the “Revolver”) was amended in October 2013 to increase the revolving commitment from $350 million to $400 million (the “Amendment”). Concurrently, the borrowing base under the Revolver was increased from $350 million to $425 million, based on a review of our total proved oil, NGL and natural gas reserves. The Amendment also provides for an extension of the current maximum leverage ratio of 4.5 to 1.0 for an additional six months and allows for the Revolver's administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two thirds of the aggregate commitment.

The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $200 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The next semi-annual redetermination is scheduled for May 2014. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $3.0 million outstanding as of September 30, 2013. As of September 30, 2013, which was prior to the Amendment, our available borrowing capacity under the Revolver was $219.0 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of September 30, 2013, the actual interest rate on the outstanding borrowings under the Revolver was 1.9375% which is derived

from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2013, commitment fees are being charged at a rate of 0.375%.

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

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

2016 Senior Notes

In May 2013, we completed a tender offer and redemption (the “Tender Offer and Redemption”) for all of our outstanding 10.375% Senior Notes due 2016 (the “2016 Senior Notes”). We paid a total of $330.9 million including consent payments and accrued interest in connection with the Tender Offer and Redemption and recognized a loss on the extinguishment of debt of $29.2 million. The loss on extinguishment of debt included non-cash charges of $10.0 million attributable to the write-off of unamortized debt issuance costs and the remaining debt discount associated with the 2016 Senior Notes.

2019 Senior Notes

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

2020 Senior Notes

On April 24, 2013, we completed a private placement of the 2020 Senior Notes. In July 2013, we completed an exchange offer that resulted in the registration of all of the 2020 Senior Notes. The 2020 Senior Notes were priced at par and interest is payable on June 15 and December 15 of each year. The 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries. Approximately $380 million of the net proceeds from the private placement, together with the Shares, were used to finance the Acquisition, including purchase price adjustments. The remaining net proceeds were used to pay down borrowings under the Revolver and to fund a portion of the Tender Offer and Redemption.

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


8.	Income Taxes

Due to the operating losses incurred, we recognized an income tax benefit for all periods presented. The effective tax benefit rates for the three and nine months ended September 30, 2013 included a deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for all current state net operating losses. The effective tax benefit rates for the three and nine months ended September 30, 2012 included a deferred tax asset valuation for certain state net operating losses.


9.	Additional Balance Sheet Detail

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



	As of
	September 30,		December 31,
	2013		2012
Other current assets:
Tubular inventory and well materials	$	2,413	$	4,033
Prepaid expenses	2,764		562
	$	5,177	$	4,595
Other assets:
Debt issuance costs	$	30,802	$	13,186
Assets of supplemental employee retirement plan (“SERP”)	3,537		3,237
Other	4,233		1,511
	$	38,572	$	17,934
Accounts payable and accrued liabilities:
Trade accounts payable	$	79,878	$	37,835
Drilling and other lease operating costs	44,537		37,703
Royalties	33,917		14,390
Production and franchise taxes	11,542		2,874
Compensation - related	6,164		6,853
Interest	38,816		5,828
Preferred stock dividends	1,725		1,687
Other	6,500		4,485
	$	223,079	$	111,655
Other liabilities:
Firm transportation obligation	$	13,525	$	14,333
Asset retirement obligations (“AROs”)	6,301		4,513
Defined benefit pension obligations	1,718		1,821
Postretirement health care benefit obligations	2,825		2,634
Deferred compensation - SERP obligation and other	3,644		3,310
Other	4,454		2,290
	$	32,467	$	28,901


10.	Fair Value Measurements

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

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of September 30, 2013, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

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



	As of
	September 30, 2013				December 31, 2012
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2016	$	—	$	—	$	316,500	$	294,759
Senior Notes due 2019	294,000		300,000		286,500		300,000
Senior Notes due 2020	786,625		775,000		—		—
	$	1,080,625	$	1,075,000	$	603,000	$	594,759

Recurring Fair Value Measurements

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



	As of September 30, 2013
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	4,424		$	—		$	4,424		$	—
Commodity derivative assets - noncurrent	1,900			—			1,900			—
Assets of SERP	3,537			3,537			—			—
Liabilities:
Commodity derivative liabilities - current	(15,305		)	—			(15,305		)	—
Commodity derivative liabilities - noncurrent	(799		)	—			(799		)	—
Deferred compensation - SERP obligations	(3,639		)	(3,639		)	—			—



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

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three and nine months ended September 30, 2013 and 2012.

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

•

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


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


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

Non-Recurring Fair Value Measurements

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

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

11. Commitments and Contingencies

Drilling and Completion Commitments

We have agreements to purchase drilling and completion services from third parties with remaining terms of up to 13 months including certain drilling services agreements assumed by us in connection with the Acquisition. The drilling agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term. As of September 30, 2013, the penalty amount would have been $8.2 million if we had terminated our agreements on that date.

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of September 30, 2013. In addition to the reserve for litigation, we maintain a suspense account which includes approximately $1.9 million representing the excess of revenues received over costs incurred attributable to these properties. As of September 30, 2013, we also have AROs of approximately $6.3 million attributable to the plugging of abandoned wells.


12.	Shareholders’ Equity

The following tables summarizes the components of our shareholders' equity and the changes therein as of and for the nine months ended September 30, 2013 and 2012:



	As of												As of
	December 31,						Dividends			All Other			September 30,
	2012			Net Loss			Declared ¹			Changes			2013
Preferred stock	$	1,150		$	—		$	—		$	—		$	1,150
Common stock ²	364			—			—			101			465
Paid-in capital ²	849,046			—			—			46,404			895,450
Retained earnings	45,790			(140,721		)	(5,175		)	—			(100,106		)
Deferred compensation obligation	3,111			—			—			(384		)	2,727
Accumulated other comprehensive loss ³	(982		)	—			—			56			(926		)
Treasury stock	(3,363		)	—			—			386			(2,977		)
	$	895,116		$	(140,721	)	$	(5,175	)	$	46,563		$	795,783

	As of												As of
	December 31,						Dividends			All Other			September 30,
	2011			Net Loss			Declared ⁴			Changes			2012
Common stock	$	270		$	—		$	—		$	1		$	271
Paid-in capital	690,131			—			—			4,228			694,359
Retained earnings	157,242			(50,148		)	(5,176		)	—			101,918
Deferred compensation obligation	3,620			—			—			(548		)	3,072
Accumulated other comprehensive loss ³	(1,084		)	—			—			69			(1,015		)
Treasury stock	(3,870		)	—			—			547			(3,323		)
	$	846,309		$	(50,148	)	$	(5,176	)	$	4,297		$	795,282

_______________________

¹ Includes dividends of $450.00 per share of 6% Convertible Perpetual Preferred Stock (the “6% Preferred Stock”).

² Includes the Shares, with a fair value of $4.23 per share, that were issued to MHR in connection with the Acquisition.

³ The Accumulated other comprehensive loss (“AOCL”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCL for the nine months ended September 30, 2013 and 2012 represent reclassifications from AOCL to net periodic benefit expense, a component of General and administrative expenses, of $86 and $106 and are presented above net of taxes of $30 and $37.

⁴ Includes dividends of $0.1125 per share of common stock.

As discussed in Note 3, we issued the Shares to MHR in April 2013 as part of the consideration paid in connection with the Acquisition. In connection with the Shares issued to MHR, we entered into a Registration Rights, Lock-Up and Buy-Back Agreement and a Standstill Agreement (collectively, the “Share Agreements”) which provided for certain rights and obligations. In September 2013, MHR sold the Shares to institutional investors in a series of private transactions. Accordingly, the Share Agreements no longer have effect.


13.	Share-Based Compensation

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

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

each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Equity-classified awards:
Stock option awards	$	612	$	950	$	2,518	$	3,108
Common, deferred and restricted stock and stock unit awards	398		332		2,263		1,125
	1,010		1,282		4,781		4,233
Liability-classified awards	1,095		165		1,544		790
	$	2,105	$	1,447	$	6,325	$	5,023


14.	Restructuring and Exit Activities

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

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Balance at beginning of period	$	16,677		$	251		$	17,263		$	576
Employee, office and other costs accrued, net	2			1,431			5			1,283
Firm transportation charge	—			17,332			—			17,332
Accretion of firm transportation obligation	410			—			1,263			—
Cash payments, net	(705		)	(1,359		)	(2,147		)	(1,536		)
Balance at end of period	$	16,384		$	17,655		$	16,384		$	17,655

Restructuring charges are included in the General and administrative caption on our Condensed Consolidated Statements of Operations. The initial charge for the firm transportation commitment was presented as a separate caption on our Consolidated Statement of Operations for the year ended December 31, 2012. The accretion of this obligation, net of any recoveries from the periodic sale of our contractual capacity, is charged as an offset to Other revenue.

The current portion of these restructuring and exit cost obligations is included in the Accounts payable and accrued liabilities caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of September 30, 2013, $2.7 million of the total obligations are classified as current while the remaining $13.6 million are classified as noncurrent.


15.	Impairments

The following table summarizes impairment charges recorded during the periods presented:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Oil and gas properties	$	132,224	$	—	$	132,224	$	28,481
Other - tubular inventory and well materials	—		700		—		835
	$	132,224	$	700	$	132,224	$	29,316

The following table summarizes the aggregate fair values of the assets described below, by asset category and the classification of inputs within the fair value measurement hierarchy, at the respective dates of impairment:



	Fair Value
	Measurement		Level 1		Level 2		Level 3
Three and nine months ended September 30, 2013:
Long-lived assets held for use	$	93,945	$	—	$	—	$	93,945
Nine months ended September 30, 2012:
Long-lived assets sold during the year	$	96,099	$	—	$	—	$	96,099

In September 2013, we recognized impairments of our assets including the Granite Wash play in the Mid-Continent region for $121.8 million, the Marcellus Shale in Pennsylvania for $9.5 million and the Selma Chalk in Mississippi for $0.9 million, in each case due primarily to market declines in current and expected future commodity prices. In June 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of those properties in the third quarter of 2012. We also recognized impairments of certain tubular inventory and well materials in both the three and nine month periods in 2012 triggered primarily by declines in asset quality.


16.	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,
	2013			2012			2013			2012
Interest on borrowings and related fees	$	22,754		$	14,156		$	57,239		$	42,462
Accretion of original issue discount	—			351			431			1,025
Amortization of debt issuance costs	961			706			2,415			2,082
Capitalized interest	(3,497		)	(234		)	(3,580		)	(732		)
	$	20,218		$	14,979		$	56,505		$	44,837


17.	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,
	2013			2012			2013			2012
Net loss	$	(98,900	)	(32,611		)	$	(140,721	)	$	(50,148	)
Less: Preferred stock dividends	(1,725		)	—			(5,175		)	—
Loss attributable to common shareholders - Basic and Diluted	$	(100,625	)	$	(32,611	)	$	(145,896	)	$	(50,148	)

Weighted-average shares - Basic	65,465			46,050			61,272			46,009
Effect of dilutive securities ¹	—			—			—			—
Weighted-average shares - Diluted	65,465			46,050			61,272			46,009

_______________________

¹ For the three and nine months ended September 30, 2013, approximately 19.2 million and less than 0.1 million potentially dilutive securities, including the 6% Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share. For the three and nine months ended September 30, 2012, less than 0.1 million potentially dilutive securities, including 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;


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


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


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


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


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


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


•	drilling and operating risks;


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


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


•	leasehold terms expiring before production can be established;


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


•	the timing of receipt of necessary regulatory permits;


•	the effect of commodity and financial derivative arrangements;


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


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


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


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


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


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


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

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.


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

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

Overview of Business

We are an independent oil and gas company engaged in the exploration, development and production of oil, natural gas liquids, or NGLs, and natural gas in various onshore regions of the United States. Our current operations and capital expenditures are substantially concentrated in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma, the Haynesville Shale and Cotton Valley in East Texas and the Selma Chalk in Mississippi. As of December 31, 2012, we had proved oil and natural gas reserves of approximately 113.5 million barrels of oil equivalent, or MMBOE. In April 2013, we acquired proved reserves of approximately 12.0 MMBOE in connection the acquisition of the Eagle Ford Shale assets of Magnum Hunter Resources Corporation, or MHR. The transaction is referred to herein as the Acquisition. In connection with a mid-year review of our total proved oil and natural gas reserves, we estimate that we have approximately 114.7 MMBOE as of June 30, 2013 including those from the Acquisition and the effect of current year production, revisions, extensions, discoveries and additions. Our current operations consist primarily of the drilling of horizontal development wells in resource or unconventional plays.

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,
	2013		2012		2013		2012
Total production (MBOE)	1,807		1,504		4,982		5,092
Daily production (BOEPD)	19,638		16,348		18,249		18,584

Product revenues, as reported	$	121,648	$	75,575	$	313,606	$	234,496
Product revenues, as adjusted for derivatives	$	117,483	$	84,812	$	315,231	$	257,279

Cash provided by operating activities	$	95,083	$	74,489	$	224,834	$	190,214
Cash paid for capital expenditures, excluding the Acquisition	$	127,645	$	68,958	$	356,964	$	257,194

Cash and cash equivalents at end of period					$	38,321	$	5,033
Debt outstanding, net of discounts, at end of period					$	1,203,000	$	676,331
Liquidation preference of convertible preferred stock outstanding at end of period					$	115,000	$	—
Credit available under revolving credit facility at end of period ¹					$	218,968	$	221,372

Net development wells drilled	8.9		6.0		28.2		18.2
Net exploratory wells drilled	—		—		—		4.8

______________________________

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

Key Developments

The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) drilling results and future development plans in the Eagle Ford Shale, (ii) integrating the properties obtained in the Acquisition, (iii) the amendment, or Amendment, of our revolving credit facility, or the Revolver, and borrowing base re-determination, (iv) hedging a portion of our oil and natural gas production through calendar year 2015 to the levels permitted by our Revolver, and our internal policies, (v) the tender offer and the redemption, or the Tender Offer and the Redemption, of our 10.375% Senior Notes due 2016, or 2016 Senior Notes and (vi) the private placement and subsequent registration of $775 million of 8.5% Senior Notes due 2020, or 2020 Senior Notes, to finance the Acquisition, the Tender Offer and the Redemption.

Drilling Results and Future Development Plans for the Eagle Ford Shale

During the nine months ended September 30, 2013, we drilled 37 gross (24.4 net) successful wells, and our joint venture partner drilled seven (2.8 net) successful non-operated wells in the Eagle Ford Shale. We also drilled one (0.5 net) well that is currently under evaluation. We also participated in two successful non-operated gross (0.5 net) wells in the Granite Wash.

Our Eagle Ford Shale production was approximately 12,489 net BOEPD during the three months ended September 30, 2013 with oil comprising approximately 78 percent, NGLs approximately 12 percent and natural gas approximately 10 percent. In the Eagle Ford Shale, we currently have a total of 158 gross (105.4 net) producing wells, 10 gross (4.8 net) operated wells completing or waiting on completion and six gross (3.2 net) operated wells being drilled as of October 30, 2013. Despite this growth, our production and revenues increased less than expected during the three months ended September 30, 2013 due to several issues associated with the outside operated Eagle Ford Shale program. Our non-operated partner recently reduced its rig count from two to one and, as a result, we have increased our operated drilling rig count by one rig.

Subsequent to the Acquisition, we have approximately 107,000 gross (67,000 net) acres, which to a large extent are contiguous and the majority of which are in the volatile oil window of the Eagle Ford Shale. Approximately 93,000 gross (61,000 net) acres are operated by us.

The average stimulation (completion) cost per frac stage for our operated Eagle Ford Shale wells was approximately $110,000 in the three months ended September 30, 2013, compared to approximately $150,000 in the three months ended June 30, 2013. The average total well cost per frac stage was approximately $350,000 in the three months ended September 30, 2013, compared to approximately $430,000 in the three months ended June 30, 2013. This decrease was due primarily to the reduced stimulation costs, as well as efficiency gains from increased use of pad drilling. A total of 16 of our recently drilled wells were drilled off of six multi-well pads, with an average effective nominal spacing of approximately 70 acres.

Acquisition of Magnum Hunter's Eagle Ford Shale Assets

On April 24, 2013, or the Date of Acquisition, we acquired producing properties and undeveloped leasehold interests in the Eagle Ford Shale play from MHR. The Acquisition was originally valued at $401 million with an effective date of January 1, 2013, or the Effective Date. On the Date of Acquisition, we paid approximately $380 million in cash, including approximately $19 million of initial purchase price adjustments related to the period from the Effective Date to the Date of Acquisition utilizing a portion of the proceeds from the private placement of the 2020 Senior Notes, and issued to MHR 10 million shares of our common stock, or Shares, with a fair value of $4.23 per share. Shortly after the Date of Acquisition, certain of our joint interest partners exercised preferential rights related to the Acquisition. We received approximately $21 million from the exercise of these rights, which was recorded as a decrease to our purchase price for the Acquisition. In September 2013, MHR sold the Shares to institutional investors in a series of private transactions.

The Acquisition included approximately 40,600 gross (17,700 net) mineral acres located in Gonzales and Lavaca Counties, Texas in areas adjacent to our current position in both counties. The acquired net assets also included working interests in 46 gross (22.1 net) producing wells and related accounts receivable and payable. At the time of the Acquisition, the estimated net oil and gas production for the acquired assets during 2013 was approximately 2,700 barrels of oil per day equivalent, or BOEPD. Based on MHR's third-party reserve engineering firm's year-end 2012 review of the acquired assets, proved reserves were approximately 12.0 MMBOE, 96 percent of which were oil and NGLs and 37 percent of which were proved developed.

Revolver Amendment and Borrowing Base Re-Determination

The Revolver was amended in October 2013 to increase the revolving commitment from $350 million to $400 million. Concurrently, the borrowing base under the Revolver was increased from $350 million to $425 million.The Amendment also provides for an extension of the current maximum leverage ratio of 4.5 to 1.0 for an additional six months and allows for the Revolver's administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two thirds of the aggregate commitment.

Commodity Hedging Activities

For the remainder of 2013, we have approximately 79 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $94.69 and $96.99 per barrel. For 2014, we have approximately 50 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $93.49 and $94.32 per barrel. For 2015, we have approximately 13 percent of our estimated oil production hedged at a weighted-average swap price of $91.74 per barrel.

For the remainder of 2013, we have approximately 63 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of between $3.82 and $4.24 per MMBtu. Through the third quarter of 2014, we have approximately 39 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of between $4.13 and $4.19 per MMBtu. We have also hedged approximately 14 percent of our estimated natural gas production for the winter 2014 - 2015 at a weighted-average swap price of $4.50 per MMBtu.

Tender Offer and Redemption for the 2016 Senior Notes

In April 2013, we initiated the Tender Offer for any and all of the $300 million principal amount of the 2016 Senior Notes. Holders of approximately 58% of the 2016 Senior Notes outstanding tendered their notes. The total consideration payable for each $1,000 principal amount of those 2016 Senior Notes tendered was $1,065.34, which included a consent payment of $30.00 per $1,000 principal amount of 2016 Senior Notes tendered. In April 2013, we paid approximately $191 million, including accrued interest of $6.5 million for the 2016 Senior Notes tendered. In May 2013, we made an irrevocable election in connection with the Redemption to redeem the remaining 42% of the 2016 Senior Notes outstanding in accordance with the 2016 Senior Notes indenture. We paid a total of $1,061.31 per $1,000 principal amount of the 2016 Senior Notes, or approximately $140 million, including accrued interest of $5.3 million, in connection with the Redemption. We recognized a loss on the extinguishment of debt of $29.2 million during the three months ended June 30, 2013 in connection with the Tender Offer and the Redemption, including non-cash charges of $10.0 million attributable to the write-off of unamortized debt issuance costs and the remaining debt discount associated with the 2016 Senior Notes.

Issuance of 2020 Senior Notes

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

Results of Operations

Three Months Ended September 30, 2013 Compared to the Three Months Ended September 30, 2012

Production

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



Crude oil	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	897.9	489.8	408.0		9,759.4	5,324.1	4,435.2		83	%
East Texas	15.5	13.1	2.4		168.1	142.5	25.7		18	%
Mid-Continent	37.8	66.3	(28.5	)	410.8	720.5	(309.7	)	(43	)%
Mississippi	3.2	3.5	(0.3	)	35.1	38.2	(3.1	)	(8	)%
Appalachia	—	0.4	(0.4	)	—	4.1	(4.1	)	(100	)%
	954.4	573.1	381.3		10,373.5	6,229.4	4,144.0		67	%



NGLs	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	142.1	49.6	92.4		1,544.0	539.2	1,004.9		186	%
East Texas	42.5	69.2	(26.7	)	462.4	752.7	(290.3	)	(39	)%
Mid-Continent	69.3	83.4	(14.1	)	753.3	906.8	(153.5	)	(17	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	0.2	(0.2	)	—	2.3	(2.3	)	(100	)%
	253.9	202.4	51.4		2,759.7	2,201.0	558.7		25	%



Natural gas	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	693	250	443		7.5	2.7	4.8		177	%
East Texas	1,129	1,424	(295	)	12.3	15.5	(3.2	)	(21	)%
Mid-Continent	674	833	(159	)	7.3	9.1	(1.7	)	(19	)%
Mississippi	1,057	1,224	(167	)	11.5	13.3	(1.8	)	(14	)%
Appalachia	37	639	(602	)	0.4	6.9	(6.5	)	(94	)%
	3,591	4,371	(780	)	39.0	47.5	(8.5	)	(18	)%



Combined total	Three Months Ended				Three Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	1,155	581	574		12,558.9	6,316.7	6,242.2		99	%
East Texas	246	320	(73	)	2,676.1	3,474.9	(798.9	)	(23	)%
Mid-Continent	219	289	(69	)	2,385.5	3,136.4	(750.9	)	(24	)%
Mississippi	179	208	(28	)	1,950.5	2,255.7	(305.2	)	(14	)%
Appalachia	6	107	(101	)	67.5	1,164.6	(1,097.1	)	(94	)%
	1,807	1,504	303		19,638.5	16,348.4	3,290.1		20	%
Certain results in the tables above may not calculate due to rounding.

Total production increased during the three months ended September 30, 2013 compared to the corresponding period of 2012 due primarily to the Acquisition and the continued expansion of our development program in South Texas, both of which were concentrated in the Eagle Ford Shale. The increase was partially offset by the effect of the sale of our Appalachian natural

gas properties in July 2012 along with natural production declines in our East Texas and Mid-Continent regions. The effect of the sale of the Appalachian properties was approximately 102 thousand barrels of oil equivalent, or MBOE. Approximately 67% of total production during the three months ended September 30, 2013 was attributable to oil and NGLs, which represents an increase of approximately 56% over the prior year period. During the three months ended September 30, 2013, our Eagle Ford Shale production represented approximately 64% of our total production as compared to approximately 39% from this play during the corresponding period of 2012.

Product Revenues and Prices

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



Crude oil	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	94,794	$	49,266	$	45,528		$	105.58	$	100.58	$	5.00
East Texas	1,629		1,232		397			105.31		94.00		11.31
Mid-Continent	3,789		6,104		(2,315		)	100.24		92.09		8.16
Mississippi	352		359		(7		)	109.05		102.10		6.94
Appalachia	—		34		(34		)	NM		89.95		NM
	$	100,564	$	56,995	$	43,569		$	105.37	$	99.45	$	5.92



NGLs	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	3,919	$	1,419	$	2,500		$	27.59	$	28.61	$	(1.02	)
East Texas	1,858		2,419		(561		)	43.68		34.93		8.75
Mid-Continent	2,435		2,823		(388		)	35.14		33.84		1.30
Mississippi	—		—		—			—		—		—
Appalachia	—		10		(10		)	—		47.17		NM
	$	8,212	$	6,671	$	1,541		$	32.34	$	32.94	$	(0.60	)



Natural gas	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	2,560	$	662	$	1,898		$	3.69	$	2.64	$	1.05
East Texas	4,001		2,724		1,277			3.54		1.91		1.63
Mid-Continent	2,367		3,109		(742		)	3.51		3.73		(0.22		)
Mississippi	3,824		3,583		241			3.62		2.93		0.69
Appalachia	120		1,831		(1,711		)	3.22		2.86		NM
	$	12,872	$	11,909	$	963		$	3.58	$	2.72	$	0.86



Combined total	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per BOE)
Texas
South Texas	$	101,273	$	51,347	$	49,926		$	87.65	$	88.36	$	(0.71	)
East Texas	7,488		6,375		1,113			30.41		19.94		10.47
Mid-Continent	8,591		12,036		(3,445		)	39.15		41.71		(2.57		)
Mississippi	4,176		3,942		234			23.27		19.00		4.28
Appalachia	120		1,875		(1,755		)	NM		17.50		NM
	$	121,648	$	75,575	$	46,073		$	67.33	$	50.25	$	17.08
NM - Not meaningful

The following table provides an analysis of the change in our revenues for the three months ended September 30, 2013 as compared to the three months ended September 30, 2012:



	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	37,920		$	5,649		$	43,569
NGL	1,693			(152		)	1,541
Natural gas	(2,125		)	3,088			963
	$	37,488		$	8,585		$	46,073

Effects of Derivatives

Our oil and gas revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. In the three months ended September 30, 2013 and 2012, we paid $4.2 million and received $9.2 million, respectively, in cash settlements of oil and gas derivatives. The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Three Months Ended
	September 30,					Favorable
	2013			2012		(Unfavorable)			% Change
Crude oil revenues as reported	$	100,564		$	56,995	$	43,569		76	%
Cash settlements on crude oil derivatives, net	(4,649		)	4,633		(9,282		)	NM
Crude oil revenues adjusted for derivatives	$	95,915		$	61,628	$	34,287		56	%

Crude oil prices per Bbl, as reported	$	105.37		$	99.45	$	5.92		6	%
Cash settlements on crude oil derivatives per Bbl	(4.87		)	8.08		(12.95		)	NM
Crude oil prices per Bbl adjusted for derivatives	$	100.50		$	107.53	$	(7.03	)	(7	)%

Natural gas revenues as reported	$	12,872		$	11,909	$	963		8	%
Cash settlements on natural gas derivatives, net	484			4,604		(4,120		)	(89	)%
Natural gas revenues adjusted for derivatives	$	13,356		$	16,513	$	(3,157	)	(19	)%

Natural gas prices per Mcf, as reported	$	3.58		$	2.72	$	0.86		32	%
Cash settlements on natural gas derivatives per Mcf	0.13			1.05		(0.92		)	(88	)%
Natural gas prices per Mcf adjusted for derivatives	$	3.71		$	3.77	$	(0.06	)	(2	)%

(Loss) Gain on Sales of Property and Equipment

In the three months ended September 30, 2013, we recognized several individually insignificant losses on the sale of property, equipment, tubular inventory and well materials, and we recognized a gain of $1.7 million during the corresponding period of 2012 related primarily to the sale of our Appalachian natural gas assets.

Other Income

Other income, which includes gathering, transportation, compression and water disposal fees and other miscellaneous operating income, net of marketing and related expenses, decreased during the three months ended September 30, 2013 due primarily to accretion expense attributable to our stranded firm transportation obligation in the Appalachian region.

Production and Lifting Costs



	Three Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Lease operating	$	8,457	$	6,206	$	(2,251	)	(36	)%
Per unit of production ($/BOE)	$	4.68	$	4.13	$	(0.55	)	(13	)%

Lease operating expense increased during the three months ended September 30, 2013 due primarily to higher chemical and water disposal costs associated with our increased oil production as well as higher downhole repairs and maintenance costs, particularly in our East Texas region. These increases were partially offset by lower compression charges.



	Three Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)		% Change
Gathering, processing and transportation	$	3,039	$	3,127	$	88	3	%
Per unit of production ($/BOE)	$	1.68	$	2.08	$	0.40	19	%

Gathering, processing and transportation charges decreased marginally during the three months ended September 30, 2013, due primarily to higher cost production in the Appalachian region during the 2012 period prior to the sale. This was substantially offset by higher production volume and higher processing costs related to increased associated gas production in the Eagle Ford Shale during the 2013 period as compared to the corresponding period of 2012.



	Three Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	4,070		$	3,017		$	(1,053	)	(35	)%
Ad valorem taxes	2,527			1,572			(955		)	(61	)%
	$	6,597		$	4,589		$	(2,008	)	(44	)%
Per unit production ($/BOE)	$	3.65		$	3.05		$	(0.60	)	(20	)%
Production/severance tax rate as a percent of product revenue	3.3		%	4.0		%

Production and ad valorem taxes increased during the three months ended September 30, 2013 due primarily to the higher level of production. In addition, we are experiencing higher property and ad valorem taxes attributable to our increased leasing and drilling activities in the Eagle Ford Shale in Gonzales and Lavaca Counties.

General and Administrative

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



	Three Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Recurring general and administrative expenses	$	10,570	$	8,756	$	(1,814	)	(21	)%
Share-based compensation (liability-classified)	1,095		165		(930		)	(564	)%
Share-based compensation (equity-classified)	1,010		1,282		272			21	%
Restructuring expenses	2		1,431		1,429			100	%
	$	12,677	$	11,634	$	(1,043	)	(9	)%
Per unit of production ($/BOE)	$	7.02	$	7.74	$	0.72		9	%
Per unit of production excluding equity-classified share-based compensation, acquisition-related transaction costs and restructuring expenses ($/BOE)	$	6.46	$	5.93	$	(0.53	)	(9	)%

Recurring general and administrative expenses increased due primarily to higher compensation, benefits and cash-based incentive charges. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, which are payable in cash in three years from the date of grant upon achievement of specified market-based performance metrics. The 2013 period includes mark-to-market charges associated with both the 2013 and 2012 PBRSU grants. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent

non-cash expenses, increased during the three months ended September 30, 2013 due primarily to a higher number of awards granted during the 2013 period.

Exploration

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



	Three Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)		% Change
Unproved leasehold amortization	$	3,759	$	8,310	$	4,551	55	%
Geological and geophysical costs	83		83		—		—	%
Other, primarily delay rentals	115		872		757		87	%
	$	3,957	$	9,265	$	5,308	57	%

Unproved leasehold amortization decreased during the three months ended September 30, 2013 as costs related to successful Eagle Ford Shale wells were transferred to proved properties. In addition, due to the significance of the unproved acreage acquired in the Acquisition, our unproved property in the Eagle Ford Shale is now considered a “significant leasehold” and as such is not subject to systematic amortization. See “Critical Accounting Estimates - Oil and Gas Properties.”

Depreciation, Depletion and Amortization (DD&A)

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



	Three Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
DD&A expense	$	62,450		$	49,331		$	(13,119	)	(27	)%
DD&A rate ($/BOE)	$	34.57		$	32.80		$	(1.77	)	(5	)%

	Production			Rates			Total
DD&A variance due to:	$	(9,928	)	$	(3,191	)	$	(13,119	)

Higher overall production volumes as well as higher depletion rates associated with oil and NGL production were the primary drivers for the increase in DD&A. Our average DD&A rate increased due primarily to higher capitalized finding and development costs attributable to our drilling program in the Eagle Ford Shale as well as lower natural gas reserves due to revisions determined as of the end of 2012.

Impairments

The following table summarizes impairment charges recorded during the periods presented:



	Three Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Oil and gas properties	$	132,224	$	—	$	(132,224	)	NM
Other - tubular inventory and well materials	—		700		700			100	%
	$	132,224	$	700	$	(131,524	)	NM

In September 2013, we recognized impairments of our assets including the Granite Wash play in the Mid-Continent region for $121.8 million, the Marcellus Shale in Pennsylvania for $9.5 million and the Selma Chalk in Mississippi for $0.9 million, in each case due primarily to market declines in current and expected future commodity prices. We recognized impairments of certain tubular inventory and well materials in the three month periods in 2012 triggered primarily by declines in asset quality.

Loss on Firm Transportation Commitment

In the three months ended September 30, 2012, we recorded a charge representing the liability for estimated discounted future net cash outflows over the remaining term of a contract for firm transportation capacity in the Appalachian region. Subsequent to the sale of our natural gas assets in that region, we no longer have production to satisfy this commitment.

Interest Expense

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



	Three Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
Interest on borrowings and related fees	$	22,754		$	14,156		$	(8,598	)	(61	)%
Accretion of original issue discount	—			351			351			100	%
Amortization of debt issuance costs	961			706			(255		)	(36	)%
Capitalized interest	(3,497		)	(234		)	3,263			1,394	%
	$	20,218		$	14,979		$	(5,239	)	(35	)%
Weighted-average debt outstanding	$	1,178,000		$	737,168
Weighted average interest rate	8.05		%	8.13		%

Interest expense increased during the three months ended September 30, 2013 due primarily to higher overall weighted-average debt outstanding and the effect of a change in the mix of outstanding debt to a larger proportion of fixed-rate debt with higher interest rates in the 2013 period as compared to a larger proportion of Revolver borrowings at lower interest rates in the 2012 period. The increase was partially offset by higher capitalized interest resulting from the significant increase in the value of our proved undeveloped and unproved properties following the Acquisition.

Derivatives

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



	Three Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
Oil and gas derivatives settled	$	(4,165	)	$	9,238		$	(13,403	)	(145	)%
Oil and gas derivatives loss	(19,870		)	(21,509		)	1,639			8	%
	$	(24,035	)	$	(12,271	)	$	(11,764	)	80	%

We paid cash settlements of $4.2 million during the three months ended September 30, 2013 and received settlements of$9.2 million during the three months ended September 30, 2012. The increase in derivatives loss was due primarily to a substantially lower volume of natural gas production being hedged during the 2013 period compared to the 2012 period.

Other

Other income decreased during the three months ended September 30, 2013 due primarily to higher interest income earned during the 2012 period.

Income Taxes



	Three Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)		% Change
Income tax benefit	$	53,106		$	22,208		$	30,898	139	%
Effective tax benefit rate	34.9		%	40.5		%

Due to the operating losses incurred, we recognized an income tax benefit during both periods. The effective tax benefit rate for the three months ended September 30, 2012 included a deferred tax asset valuation allowance related to the inability to recognize tax benefits for certain state net operating losses. The 2013 period includes a deferred tax asset valuation allowance for all state net operating losses.

Nine Months Ended September 30, 2013 Compared to the Nine Months Ended September 30, 2012

Production

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



Crude oil	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	2,226.0	1,451.9	774.1		8,153.9	5,298.8	2,855.1		53	%
East Texas	47.0	48.6	(1.6	)	172.3	177.3	(5.1	)	(3	)%
Mid-Continent	128.2	180.5	(52.3	)	469.7	658.9	(189.2	)	(29	)%
Mississippi	10.0	11.3	(1.3	)	36.8	41.4	(4.6	)	(11	)%
Appalachia	0.1	0.9	(0.8	)	0.5	3.3	(2.8	)	(85	)%
	2,411.5	1,693.2	718.2		8,833.2	6,179.7	2,653.4		42	%



NGLs	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	355.6	135.1	220.5		1,302.6	493.0	809.6		163	%
East Texas	154.6	208.2	(53.6	)	566.3	759.9	(193.7	)	(26	)%
Mid-Continent	238.1	300.8	(62.7	)	872.0	1,097.7	(225.7	)	(21	)%
Mississippi	—	—	—		—	—	—		NM
Appalachia	—	0.6	(0.6	)	—	2.2	(2.2	)	(100	)%
	748.3	644.7	103.6		2,740.9	2,352.9	388.0		16	%



Natural gas	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	1,798	688	1,110		6.6	2.5	4.1		161	%
East Texas	3,460	4,606	(1,146	)	12.7	16.8	(4.1	)	(25	)%
Mid-Continent	2,205	2,782	(577	)	8.1	10.2	(2.1	)	(21	)%
Mississippi	3,360	3,794	(434	)	12.3	13.8	(1.5	)	(11	)%
Appalachia	110	4,654	(4,544	)	0.4	17.0	(16.6	)	(98	)%
	10,933	16,524	(5,591	)	40.0	60.3	(20.3	)	(34	)%



Combined total	Nine Months Ended				Nine Months Ended
	September 30,		Favorable		September 30,		Favorable
	2013	2012	(Unfavorable)		2013	2012	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	2,881	1,702	1,180		10,554.4	6,210.5	4,343.9		69	%
East Texas	778	1,024	(246	)	2,850.7	3,738.9	(888.2	)	(24	)%
Mid-Continent	734	945	(211	)	2,688.1	3,448.8	(760.7	)	(22	)%
Mississippi	570	644	(74	)	2,087.9	2,349.1	(261.1	)	(11	)%
Appalachia	18	777	(759	)	67.6	2,836.3	(2,768.7	)	(98	)%
	4,982	5,092	(110	)	18,248.8	18,583.6	(334.8	)	(2	)%

The marginal decrease in total production during the nine months ended September 30, 2013 compared to the corresponding period of 2012 was due primarily to the effect of the sale of our Appalachian natural gas assets in July 2012 and production declines in our East Texas and Mid-Continent regions. The decrease was substantially offset by an increase in oil, NGL and natural gas production attributable to our drilling activity in the Eagle Ford Shale. The effect of the sale of the Appalachian properties was approximately 741 MBOE. Approximately 63% of total production during the nine months ended September 30, 2013 was attributable to oil and NGLs, which represents an increase of approximately 35% over the prior year

period. During the nine months ended September 30, 2013, our Eagle Ford Shale production represented approximately 58% of our total production as compared to approximately 33% from this play during the corresponding period of 2012.

Product Revenues and Prices

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



Crude oil	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	232,771	$	151,334	$	81,437		$	104.57	$	104.23	$	0.34
East Texas	4,736		4,759		(23		)	100.70		97.94		2.77
Mid-Continent	11,895		16,732		(4,837		)	92.76		92.68		0.08
Mississippi	1,075		1,192		(117		)	107.09		105.17		1.92
Appalachia	12		83		(71		)	86.96		91.81		NM
	$	250,489	$	174,100	$	76,389		$	103.87	$	102.82	$	1.05



NGLs	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	9,134	$	4,507	$	4,627		$	25.68	$	33.36	$	(7.68	)
East Texas	5,090		7,911		(2,821		)	32.93		37.99		(5.07		)
Mid-Continent	8,428		10,849		(2,421		)	35.40		36.07		(0.67		)
Mississippi	—		—		—			—		—		—
Appalachia	—		31		(31		)	—		50.74		NM
	$	22,652	$	23,298	$	(646	)	$	30.27	$	36.14	$	(5.87	)



Natural gas	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	6,573	$	1,540	$	5,033		$	3.66	$	2.24	$	1.42
East Texas	11,576		9,333		2,243			3.35		2.03		1.32
Mid-Continent	8,775		4,844		3,931			3.98		1.74		2.24
Mississippi	12,549		10,165		2,384			3.74		2.68		1.06
Appalachia	992		11,216		(10,224		)	NM		2.41		NM
	$	40,465	$	37,098	$	3,367		$	3.70	$	2.25	$	1.46



Combined total	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2013		2012		(Unfavorable)			2013		2012		(Unfavorable)
								($ per BOE)
Texas
South Texas	$	248,478	$	157,381	$	91,097		$	86.24	$	92.49	$	(6.25	)
East Texas	21,402		22,003		(601		)	27.50		21.48		6.02
Mid-Continent	29,098		32,425		(3,327		)	39.65		34.31		5.34
Mississippi	13,624		11,357		2,267			23.90		17.64		6.26
Appalachia	1,004		11,330		(10,326		)	NM		14.58		NM
	$	313,606	$	234,496	$	79,110		$	62.95	$	46.05	$	16.90

As illustrated below, the effect of higher oil and NGL production volume coupled with improved crude oil and natural gas prices more than offset the overall decline in NGL prices and natural gas production volume.

The following table provides an analysis of the change in our revenues for the nine months ended September 30, 2013 as compared to the nine months ended September 30, 2012:



	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	73,846		$	2,543		$	76,389
NGL	3,743			(4,389		)	(646		)
Natural gas	(12,552		)	15,919			3,367
	$	65,037		$	14,073		$	79,110

Effects of Derivatives

In the nine months ended September 30, 2013 and 2012, we received $1.6 million and $22.8 million, respectively, in cash settlements of oil and gas derivatives. The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Crude oil revenues as reported	$	250,489	$	174,100	$	76,389		44	%
Cash settlements on crude oil derivatives, net	628		4,461		(3,833		)	NM
Crude oil revenues adjusted for derivatives	$	251,117	$	178,561	$	72,556		41	%

Crude oil prices per Bbl, as reported	$	103.87	$	102.82	$	1.05		1	%
Cash settlements on crude oil derivatives per Bbl	0.26		2.63		(2.37		)	NM
Crude oil prices per Bbl adjusted for derivatives	$	104.13	$	105.45	$	(1.32	)	(1	)%

Natural gas revenues as reported	$	40,465	$	37,098	$	3,367		9	%
Cash settlements on natural gas derivatives, net	997		18,322		(17,325		)	(95	)%
Natural gas revenues adjusted for derivatives	$	41,462	$	55,420	$	(13,958	)	(25	)%

Natural gas prices per Mcf, as reported	$	3.70	$	2.25	$	1.46		65	%
Cash settlements on natural gas derivatives per Mcf	0.09		1.11		(1.02		)	(92	)%
Natural gas prices per Mcf adjusted for derivatives	$	3.79	$	3.36	$	0.44		13	%

(Loss) Gain on Sales of Property and Equipment

In the nine months ended September 30, 2013, we recognized a loss on the assignment of certain properties in West Virginia associated with our 2012 sale of Appalachian natural gas assets. In the nine months ended September 30, 2012, we recognized a gain attributable to the sale of substantially all of our Appalachian natural gas assets. In addition, we recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well material during both periods.

Other Income

Other income, which includes gathering, transportation, compression and water disposal fees and other miscellaneous operating income, net of marketing and related expenses, decreased during the nine months ended September 30, 2013 due primarily to accretion expense attributable to our stranded firm transportation obligation in the Appalachian region partially offset by the gain on the sale of certain seismic data.

Production and Lifting Costs



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Lease operating	$	24,891	$	24,613	$	(278	)	(1	)%
Per unit of production ($/BOE)	$	5.00	$	4.83	$	(0.17	)	(4	)%

Lease operating expense increased marginally during the nine months ended September 30, 2013 due primarily to higher downhole repairs and maintenance costs, particularly in our East Texas region, and higher water disposal and chemical costs associated with our increased oil production. These increases were substantially offset by the effect of the sale of our higher-cost Appalachian properties in July 2012.



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)		% Change
Gathering, processing and transportation	$	9,598	$	11,672	$	2,074	18	%
Per unit of production ($/BOE)	$	1.93	$	2.29	$	0.36	16	%

Gathering, processing and transportation charges decreased during the nine months ended September 30, 2013 due primarily to the effect of the sale of our Appalachian natural gas properties in July 2012 partially offset by higher processing costs related to increased associated gas production in the Eagle Ford Shale as compared to the corresponding period of 2012.



	Nine Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	12,762		$	4,427		$	(8,335	)	(188	)%
Ad valorem taxes	6,770			3,488			(3,282		)	(94	)%
	$	19,532		$	7,915		$	(11,617	)	(147	)%
Per unit production ($/BOE)	$	3.92		$	1.55		$	(2.37	)	(153	)%
Production/severance tax rate as a percent of product revenue	4.1		%	1.9		%

Production and ad valorem taxes increased during the nine months ended September 30, 2013 due primarily to the recognition of approximately $4 million of non-recurring credits in the 2012 period for severance tax rebates for certain horizontal and ultra-deep wells in Oklahoma and Texas. In addition, we are experiencing higher property and ad valorem taxes attributable to our increased leasing and drilling activities in the Eagle Ford Shale in Gonzales and Lavaca Counties.

General and Administrative

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



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Recurring general and administrative expenses	$	30,550	$	29,216	$	(1,334	)	(5	)%
Share-based compensation (liability-classified)	1,544		790		(754		)	(95	)%
Share-based compensation (equity-classified)	4,781		4,233		(548		)	(13	)%
Acquisition-related transaction costs	2,396		—		(2,396		)	NM
Restructuring expenses	5		1,283		1,278			100	%
	$	39,276	$	35,522	$	(3,754	)	(11	)%
Per unit of production ($/BOE)	$	7.88	$	6.98	$	(0.90	)	(13	)%
Per unit of production excluding equity-classified share-based compensation, acquisition-related transaction costs and restructuring expenses ($/BOE)	$	6.44	$	5.89	$	(0.55	)	(9	)%

mark-to-market charges associated with both the 2013 and 2012 PBRSU grants. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, increased during the nine months ended September 30, 2013 due primarily to the recognition of expense on the 2013 grant date for certain awards as a result of the retirement eligibility of an officer. We incurred transaction costs of $2.4 million associated with the Acquisition including advisory, legal, due diligence and other professional fees. Restructuring charges during the 2012 period include termination benefits and a provision for lease costs attributable to exit activities in connection with the sale of our Appalachian assets.

Exploration

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



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Unproved leasehold amortization	$	14,167	$	24,765	$	10,598		43	%
Geological and geophysical costs	2,880		441		(2,439		)	NM
Other, primarily delay rentals	1,050		1,441		391			27	%
	$	18,097	$	26,647	$	8,550		32	%

Unproved leasehold amortization declined during the nine months ended September 30, 2013 as costs related to successful Eagle Ford Shale wells were transferred to proved properties and because unproved acreage related to the Acquisition is not subject to amortization. Geological and geophysical costs increased during the 2013 period due primarily to the purchase of certain seismic data for the South Texas region. Delay rentals decreased during the 2013 period due primarily to the sale of our Appalachian natural gas properties despite the increase in undeveloped leasehold acreage acquired in connection with the Acquisition.

Depreciation, Depletion and Amortization

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



	Nine Months Ended
	September 30,					Favorable
	2013		2012			(Unfavorable)			% Change
DD&A expense	$	178,355	$	151,888		$	(26,467	)	(17	)%
DD&A rate ($/BOE)	$	35.80	$	29.83		$	(5.97	)	(20	)%

	Production		Rates			Total
DD&A variance due to:	$	3,281	$	(29,748	)	$	(26,467	)

The effect of lower overall production volumes on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average DD&A rate increased due primarily to higher capitalized finding and development costs attributable to our drilling program in the Eagle Ford Shale as well as lower natural gas reserves due to revisions determined as of the end of 2012.

Impairments

The following table summarizes impairment charges recorded during the periods presented:



	Nine Months Ended
	September 30,				Favorable
	2013		2012		(Unfavorable)			% Change
Oil and gas properties	$	132,224	$	28,481	$	(103,743	)	NM
Other - tubular inventory and well materials	—		835		835			100	%
	$	132,224	$	29,316	$	(102,908	)	NM

million, in each case due primarily to market declines in current and expected future commodity prices. In June 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of those properties in the third quarter of 2012. We also recognized impairments of certain tubular inventory and well materials in the nine month period in 2012 triggered primarily by declines in asset quality.

Loss on Firm Transportation Commitment

In the nine months ended September 30, 2012, we recorded a charge representing the liability for estimated discounted future net cash outflows over the remaining term of a contract for firm transportation capacity in the Appalachian region. Subsequent to the sale of our natural gas assets in that region, we no longer have production to satisfy this commitment.

Interest Expense

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



	Nine Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)			% Change
Interest on borrowings and related fees	$	57,239		$	42,462		$	(14,777	)	(35	)%
Accretion of original issue discount	431			1,025			594			58	%
Amortization of debt issuance costs	2,415			2,082			(333		)	(16	)%
Capitalized interest	(3,580		)	(732		)	2,848			389	%
	$	56,505		$	44,837		$	(11,668	)	(26	)%
Weighted-average debt outstanding	$	953,038		$	728,131
Weighted average interest rate	8.41		%	8.21		%

Interest expense increased during the nine months ended September 30, 2013 due primarily to higher overall weighted-average debt outstanding and the effect of a change in the mix of outstanding debt to a larger proportion of fixed-rate debt with higher interest rates in the 2013 period as compared to a larger proportion of Revolver borrowings at lower interest rates in the 2012 period. The increase was partially offset by higher capitalized interest resulting from the significant increase in the value of our proved undeveloped and unproved properties following the Acquisition.

Derivatives

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



	Nine Months Ended
	September 30,					Favorable
	2013			2012		(Unfavorable)			% Change
Oil and gas derivatives settled	$	1,625		$	22,783	$	(21,158	)	(93	)%
Oil and gas derivatives (loss) gain	(24,833		)	7,061		(31,894		)	(452	)%
Interest rate swaps settled	—			1,406		(1,406		)	(100	)%
	$	(23,208	)	$	31,250	$	(54,458	)	(174	)%

We received cash settlements of $1.6 million, all of which were attributable to commodity derivatives, during the nine months ended September 30, 2013 and $24.2 million, including $1.2 million attributable to the termination of an interest rate swap agreement, during the nine months ended September 30, 2012. The loss in the 2013 period is due primarily to period-end oil prices exceeding hedged prices as well as a substantially lower volume of natural gas production being hedged during the 2013 period as compared to the 2012 period.

Other

Other income increased during the nine months ended September 30, 2013 due primarily to income earned from a vendor account processing incentive bonus.

Income Taxes



	Nine Months Ended
	September 30,						Favorable
	2013			2012			(Unfavorable)		% Change
Income tax benefit	$	75,577		$	32,444		$	43,133	133	%
Effective tax benefit rate	34.9		%	39.3		%

Due to the operating losses incurred, we recognized an income tax benefit during both periods. The effective tax benefit rate for the nine months ended September 30, 2012 included a deferred tax asset valuation allowance related to the inability to recognize tax benefits for certain state net operating losses. The 2013 period includes a deferred tax asset valuation allowance for all current state net operating losses.

Liquidity and Capital Resources

Sources of Liquidity

Our business strategy contemplates capital expenditures in excess of our projected operating cash flows for 2013. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our 2013 capital program with operating cash flows, borrowings under the Revolver, proceeds from the sale of non-core assets and supplemental issues of debt and equity if appropriate. We have no debt maturities until September 2017 when the Revolver matures.

The Revolver was amended in October 2013 to increase the revolving commitment from $350 million to $400 million. Concurrently, the borrowing base under the Revolver was increased from $350 million to $425 million, based on a review of our total proved oil, NGL and natural gas reserves. The Amendment also provides for an extension of the current maximum leverage ratio of 4.5 to 1.0 for an additional six months and allows for the Revolver's administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two thirds of the aggregate commitment.

As of September 30, 2013, which was prior to the Amendment, we had $219.0 million of unused borrowing capacity available to us under the Revolver. That borrowing capacity was determined by reducing the then commitment of $350 million by outstanding borrowings and outstanding letters of credit of $3.0 million. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions.

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



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended September 30, 2013	$	108,065	$	133,000	1.9340	%
Nine months ended September 30, 2013	$	61,546	$	133,000	1.8599	%

Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, we actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices and our operating strategy. During the nine months ended September 30, 2013, our commodity derivatives portfolio provided $0.6 million of cash inflows related to lower than anticipated prices received for our oil production and $1.0 million of cash inflows attributable to lower than anticipated prices received for our natural gas production.

For the remainder of 2013, we have hedged approximately 79 percent of our estimated crude oil production, at weighted average floor/swap and ceiling prices of between $94.69 and $96.99 per barrel. In addition, we have hedged approximately 63 percent of our estimated natural gas production for 2013, at weighted average floor/swap and ceiling prices of between $3.82 and $4.24 per MMBtu.

Cash Flows

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



	Nine Months Ended
	September 30,
	2013			2012			Variance
Cash flows from operating activities
Operating cash flows, net	$	172,776		$	119,244		$	53,532
Working capital changes, net	75,647			45,014			30,633
Commodity derivative settlements received, net:							—
Crude oil	628			4,461			(3,833		)
Natural gas	997			18,322			(17,325		)
Interest payments, net of amounts capitalized	(20,671		)	(27,865		)	7,194
Income tax refunds received	—			32,574			(32,574		)
Acquisition transaction costs paid	(2,396		)	—			(2,396		)
Restructuring and exit costs paid	(2,147		)	(1,536		)	(611		)
Net cash provided by operating activities	224,834			190,214			34,620
Cash flows from investing activities
Acquisition and settlement of related obligations, net	(401,262		)	—			(401,262		)
Capital expenditures - property and equipment	(356,964		)	(257,194		)	(99,770		)
Proceeds from sales of assets and other, net	653			93,456			(92,803		)
Net cash used in investing activities	(757,573		)	(163,738		)	(593,835		)
Cash flows from financing activities
Proceeds from the issuance of senior notes	775,000			—			775,000
Retirement of senior notes	(319,090		)	—			(319,090		)
Proceeds from revolving credit facility borrowings, net	128,000			(22,000		)	150,000
Debt issuance costs paid	(25,199		)	(1,779		)	(23,420		)
Dividends paid on preferred and common stock	(5,137		)	(5,176		)	39
Other, net	(164		)	—			(164		)
Net cash provided by (used in) financing activities	553,410			(28,955		)	582,365
Net increase (decrease) in cash and cash equivalents	$	20,671		$	(2,479	)	$	23,150

Cash Flows From Operating Activities

Higher realized cash flows from higher operating margin oil and NGL operations, despite the absence of production from the divested Appalachian natural gas assets, resulted in an increase in our cash flows from operating activities during the nine months ended September 30, 2013 as compared to the corresponding period in 2012. We also had lower amounts paid for interest during the 2013 period due to lower average outstanding Revolver balances and the timing of interest payments on our senior indebtedness. When comparing the 2013 and 2012 periods, these increases to cash flow were partially offset by (i) the receipt of a significant federal income tax refund during the 2012 period, (ii) the realization of substantially lower net settlements from our commodity derivatives portfolio during the 2013 period due primarily to realized crude oil prices exceeding hedged prices as well as a significantly lower volume of natural gas production subject to hedges, (iii) the payment of transaction costs, including advisory, legal, due diligence and other professional fees in connection with the Acquisition during the 2013 period and (iv) higher restructuring and exit costs payments during the 2013 period due primarily to ongoing contractual payments for firm transportation capacity in the Appalachian region.

Cash Flows From Investing Activities

Through September 30, 2013, we paid approximately $401 million for the Acquisition. This amount includes: (i) approximately $379 million, including approximately $19 million of initial purchase price adjustments, paid to MHR at settlement, (ii) approximately $43 million, net paid subsequent to the Date of Acquisition to settle obligations assumed in the Acquisition, and (iii) the receipt of approximately $21 million of proceeds received from certain of our joint interest partners upon the exercise of their preferential rights with respect to the Acquisition.

Capital expenditures were substantially higher during the nine months ended September 30, 2013 as compared to the corresponding period during 2012 due primarily to a higher level of drilling activity and pipeline construction attributable to the expansion of our operations in the Eagle Ford Shale.

Proceeds from sales of non-core properties and other assets were received during both the 2013 and 2012 periods. The amounts received during the 2013 period were attributable primarily to the assignment of certain properties in West Virginia associated with our 2012 sale of Appalachian natural gas assets. The amounts received during the 2012 period were attributable to the sale of substantially all of our natural gas assets in the Appalachian region as well as our remaining undeveloped acreage in Butler and Armstrong Counties, Pennsylvania.

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



	Nine Months Ended
	September 30,
	2013		2012
Oil and gas:
Development drilling	$	300,915	$	188,071
Exploration drilling	13,833		47,365
Geological and geophysical (seismic) costs	2,880		441
Lease acquisitions	29,517		17,341
Pipeline, gathering facilities and other	11,436		13,310
	358,581		266,528
Other - Corporate	2,137		490
Total capital program costs	$	360,718	$	267,018

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



	Nine Months Ended
	September 30,
	2013			2012
Total capital program costs	$	360,718		$	267,018
Less:
Capital program costs recorded as exploration expenses
Geological and geophysical (seismic)	(2,880		)	(441		)
Other, primarily delay rentals	(1,050		)	(1,417		)
Transfers from tubular inventory and well materials	(1,126		)	(12,420		)
Changes in accrued capitalized costs	(5,725		)	655
Add:
Tubular inventory, well materials and completion services purchased in advance of drilling	3,447			3,067
Capitalized interest	3,580			732
Total cash paid for capital expenditures	$	356,964		$	257,194

Cash Flows From Financing Activities

In April 2013, we issued the the 2020 Senior Notes which were used to fund the Acquisition and a portion of the Tender Offer and Redemption of all of our outstanding 2016 Senior Notes. We incurred and paid costs associated with the issuance of the 2020 Senior Notes as well as costs associated with an amendment to our Revolver. Cash flows from financing activities for the nine months ended September 30, 2013 include borrowings under the Revolver while the 2012 period includes net repayments under the Revolver which were funded by the proceeds from the sale of our Appalachian natural gas assets and the federal income tax refund. The 2013 period includes dividends paid on our 6% Series A Convertible Perpetual Preferred Stock, or the 6% Preferred Stock, and the 2012 period includes dividends paid on our common stock.

Financial Condition

As of September 30, 2013, or prior to the Amendment of the Revolver, we had $219.0 million of unused borrowing capacity available to us. That borrowing capacity was determined by reducing the previous commitment of $350 million by outstanding borrowings of $128 million and outstanding letters of credit of $3.0 million. The Revolver includes certain financial covenants as described below that could limit borrowings under the Revolver to amounts below the current commitment and borrowing base. The indentures for our senior notes include an incurrence test which could potentially limit our ability to issue additional debt if our interest coverage ratio, as defined in the indentures, is less than 2.25 times consolidated EBITDAX, a non-GAAP measure. Our actual interest coverage ratio for the twelve month period ended September 30, 2013 was 3.68 times consolidated EBITDAX.

Debt and Credit Facilities and Preferred Stock Financing

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of September 30, 2013, the actual interest rate applicable to the Revolver was 1.9375% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2013, commitment fees are being charged at a rate of 0.375%.

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

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

2020 Senior Notes. The 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on May 1 and November 1 of each year. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively 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.

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

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

Covenant Compliance

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

•

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


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

As of September 30, 2013 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants. The following table summarizes the actual results of our financial covenant compliance under the Revolver as of and for the period ended September 30, 2013:



	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.5 to 1	3.6 to 1
Current ratio	> 1.0 to 1	1.8 to 1

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

Future Capital Needs and Commitments

In 2013, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $530 million. The capital expenditures for 2013 will be funded primarily by operating cash flows, borrowings under the Revolver, proceeds from the sale of non-core assets and supplemental issues of debt and equity if appropriate. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the overall availability of capital.

Based on expenditures to date and forecasted activity for the remainder of 2013, we expect to allocate capital expenditures as follows: Eagle Ford Shale (approximately 94 percent) and Mid-Continent region and all other areas (approximately six percent). This allocation includes approximately 86 percent for drilling and completions, nine percent for leasehold acquisition and five percent for pipeline, gathering, seismic, facilities and other projects. The total forecasted activity assumes a drilling program utilizing a total of six drilling rigs in the Eagle Ford Shale, five of which would be operated and one of which would be non-operated. We anticipate that we will allocate substantially all of our capital expenditures to oil and NGL projects.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of September 30, 2013, we have recorded asset retirement obligations of $6.3 million attributable to these activities. The regulatory burden on the

oil and natural gas industry increases the cost of doing business and consequently affects our profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or regulations or the adoption of new environmental laws or regulations, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2012. The following developments are discussed with respect to their applicability during the nine months ended September 30, 2013 and future periods.

Oil and Gas Properties

In accordance with our accounting policies, we provide for the impairment of unproved leaseholds whose acquisition costs are insignificant to total oil and gas properties through a provision for amortization charged to exploration expense over the lesser of five years or the average remaining lease term. We assess unproved leaseholds whose acquisition costs are relatively significant for impairment on a property-by-property basis. For the past several years, we have not had any unproved leaseholds that were deemed significant. Subsequent to the Acquisition, our unproved leaseholds in the Eagle Ford Shale are now considered significant and are subject to impairment on a stand-alone basis effective July 1, 2013. Based on our assessment of this unproved leasehold for the three months ended September 30, 2013, there is no impairment. Furthermore, we anticipate transferring material amounts representing the cost of unproved leaseholds to proved properties in the fourth quarter of 2013 and future periods as we continue our development activities in the Eagle Ford Shale. Accordingly, we anticipate that our future charges for unproved leasehold amortization will decrease from historical levels.

Considering the magnitude of unproved leaseholds and proved undeveloped properties acquired, the related indebtedness that we incurred to finance the Acquisition, and timing of the development plans that we have for the Eagle Ford Shale, we anticipate the capitalization of interest costs to increase substantially for future periods. In the three months ended September 30, 2013, we capitalized $3.5 million of interest costs attributable to qualifying activities that are in process to bring our Eagle Ford Shale unproved leaseholds and proved undeveloped properties into production.

New Accounting Standards

Effective January 1, 2013, we adopted Accounting Standards Update No. 2013-02, Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”). The disclosures required by ASU 2013-02 are included in Note 12 to the Condensed Consolidated Financial Statements. The adoption of ASU 2013-02 did not have a significant impact on our Condensed Consolidated Financial Statements and Notes to the Condensed Consolidated Financial Statements.

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. As of September 30, 2013, we had borrowings of $128 million under the Revolver at an interest rate of 1.9375%. Assuming a constant borrowing level of $128 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense of approximately $1.3 million on an annual basis.

Commodity Price Risk

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

As of September 30, 2013, we reported a commodity derivative asset of $6.3 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of September 30, 2013.

During the nine months ended September 30, 2013, we reported net commodity derivative losses of $23.2 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, 2013:



		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2013	Collars	2,400	$	91.04	100.02	$	—	$	707
First quarter 2014	Collars	1,500	$	93.33	102.80	112		154
Second quarter 2014	Collars	1,500	$	93.33	102.80	287		67
Fourth quarter 2013	Swaps	7,000	$	95.94		224		3,806
First quarter 2014	Swaps	7,500	$	93.86		292		3,580
Second quarter 2014	Swaps	7,500	$	93.86		767		2,363
Third quarter 2014	Swaps	8,000	$	93.18		1,041		1,841
Fourth quarter 2014	Swaps	8,000	$	93.18		1,434		1,052
First quarter 2014	Swaption	812	$	100.00		—		111
Second quarter 2014	Swaption	812	$	100.00		—		111
Third quarter 2014	Swaption	812	$	100.00		—		112
Fourth quarter 2014	Swaption	812	$	100.00		—		112

Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2013	Collars	15,000	$	3.67	4.37	242		—
First quarter 2014	Collars	5,000	$	4.00	4.50	131		—
Fourth quarter 2013	Swaps	10,000	$	4.04		411		—
First quarter 2014	Swaps	10,000	$	4.28		407		—
Second quarter 2014	Swaps	15,000	$	4.10		433		—
Third quarter 2014	Swaps	15,000	$	4.10		344		—
Fourth quarter 2014	Swaps	5,000	$	4.50		240		—
First quarter 2015	Swaps	5,000	$	4.50		151		—
Settlements to be paid in subsequent period						—		2,608

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	$	(45.1	)	$	42.1
Effect on the fair value of natural gas derivatives	$	(6.0	)	$	6.3

Effect on the remainder of 2013 operating income, excluding crude oil derivatives	$	10.2		$	(10.2	)
Effect on the remainder of 2013 operating income, excluding natural gas derivatives	$	3.2		$	(3.2	)


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, 2013. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2013, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

Part II. OTHER INFORMATION


Item 6	Exhibits



(3.1)	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on September 27, 2013).

(10.1)	Form of Agreement for Deferred Common Stock Unit Awards under the Penn Virginia Corporation 2013 Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on July 30, 2013).

(12.1)	Statement of Computation of Ratio of Earnings to Fixed Charges and Preferred Dividends Calculation.

(31.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(31.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(32.1)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(32.2)	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(101.INS)	XBRL Instance Document

(101.SCH)	XBRL Taxonomy Extension Schema Document

(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document

(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document

(101.LAB)	XBRL Taxonomy Extension Label Linkbase Document

(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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



	PENN VIRGINIA CORPORATION

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

October 30, 2013	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President and Controller