PVA-2014.06.30-10Q

10-Q 1 pva-20140630x10q.htm 10-Q PVA-2014.06.30-10Q

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 June 30, 2014



¨	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 July 25, 2014, 71,480,385 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 June 30, 2014

Table of Contents



Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2014 and 2013	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended June 30, 2014 and 2013	4
	Condensed Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2014 and 2013	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Acquisitions and Divestitures	7
	4. Accounts Receivable and Major Customers	9
	5. Derivative Instruments	9
	6. Property and Equipment	12
	7. Long-Term Debt	12
	8. Income Taxes	13
	9. Additional Balance Sheet Detail	13
	10. Fair Value Measurements	15
	11. Commitments and Contingencies	16
	12. Shareholders’ Equity	17
	13. Share-Based Compensation	18
	14. Restructuring and Exit Activities	18
	15. Interest Expense	19
	16. Earnings per Share	19
Forward-Looking Statements		20
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	21
	Key Developments	22
	Results of Operations	24
	Financial Condition	36
	Critical Accounting Estimates	41
3.	Quantitative and Qualitative Disclosures About Market Risk	41
4.	Controls and Procedures	43
Part II - Other Information
1.	Legal Proceedings	44
6.	Exhibits	44
Signatures		45

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Revenues
Crude oil	$	112,090		$	86,867		$	217,666		$	149,925
Natural gas liquids (NGLs)	8,037			7,313			17,410			14,440
Natural gas	16,302			15,554			34,505			27,593
Gain (loss) on sales of property and equipment, net	(51		)	256			56,775			(293		)
Other, net	2,983			(335		)	2,870			1,188
Total revenues	139,361			109,655			329,226			192,853
Operating expenses
Lease operating	12,403			8,629			22,807			16,434
Gathering, processing and transportation	3,526			2,980			6,487			6,559
Production and ad valorem taxes	7,510			6,976			14,815			12,935
General and administrative	14,840			15,656			31,528			26,599
Exploration	3,373			7,845			12,009			14,140
Depreciation, depletion and amortization	71,437			64,329			143,624			115,905
Impairment	117,908			—			117,908			—
Total operating expenses	230,997			106,415			349,178			192,572
Operating income (loss)	(91,636		)	3,240			(19,952		)	281
Other income (expense)
Interest expense	(23,229		)	(21,808		)	(45,763		)	(36,287		)
Loss on extinguishment of debt	—			(29,157		)	—			(29,157		)
Derivatives	(42,665		)	8,588			(58,327		)	827
Other	30			17			31			44
Loss before income taxes	(157,500		)	(39,120		)	(124,011		)	(64,292		)
Income tax benefit	56,716			13,682			42,452			22,471
Net loss	(100,784		)	(25,438		)	(81,559		)	(41,821		)
Preferred stock dividends	(1,718		)	(1,725		)	(3,440		)	(3,450		)
Induced conversion of preferred stock	(3,368		)	—			(3,368		)	—
Net loss attributable to common shareholders	$	(105,870	)	$	(27,163	)	$	(88,367	)	$	(45,271	)
Net loss per share:
Basic	$	(1.59	)	$	(0.43	)	$	(1.34	)	$	(0.77	)
Diluted	$	(1.59	)	$	(0.43	)	$	(1.34	)	$	(0.77	)

Weighted average shares outstanding - basic	66,514			62,899			66,065			59,141
Weighted average shares outstanding - diluted	66,514			62,899			66,065			59,141

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						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net loss	$	(100,784	)	$	(25,438	)	$	(81,559	)	$	(41,821	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $13 and $26 in 2014 and $10 and $20 in 2013	24			19			49			38
	24			19			49			38
Comprehensive loss	$	(100,760	)	$	(25,419	)	$	(81,510	)	$	(41,783	)

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
	June 30,			December 31,
	2014			2013
Assets
Current assets
Cash and cash equivalents	$	25,095		$	23,474
Accounts receivable, net of allowance for doubtful accounts	238,325			194,403
Derivative assets	—			3,830
Deferred income taxes	6,065			6,065
Assets held for sale	71,957			—
Other current assets	5,631			5,924
Total current assets	347,073			233,696
Property and equipment, net (successful efforts method)	2,207,754			2,237,304
Derivative assets	—			1,552
Other assets	32,853			34,535
Total assets	$	2,587,680		$	2,507,087

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	240,254		$	248,004
Derivative liabilities	44,298			10,141
Total current liabilities	284,552			258,145
Other liabilities	44,901			33,386
Derivative liabilities	8,508			—
Deferred income taxes	103,327			145,752
Long-term debt	1,130,000			1,281,000

Commitments and contingencies (Note 11)

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A - 8,880 and 11,500 shares issued as of June 30, 2014 and December 31, 2013 and Series B - 32,500 shares issued as of June 30, 2014, each with a redemption value of $10,000 per share	4,138			1,150
Common stock of $0.01 par value – 128,000,000 shares authorized; 69,922,551 and 65,306,748 shares issued as of June 30, 2014 and December 31, 2013, respectively	512			466
Paid-in capital	1,204,224			891,351
Accumulated deficit	(192,547		)	(104,180		)
Deferred compensation obligation	3,001			2,792
Accumulated other comprehensive income	316			267
Treasury stock – 245,256 and 233,063 shares of common stock, at cost, as of June 30, 2014 and December 31, 2013, respectively	(3,252		)	(3,042		)
Total shareholders’ equity	1,016,392			788,804
Total liabilities and shareholders’ equity	$	2,587,680		$	2,507,087

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)



	Six Months Ended
	June 30,
	2014			2013
Cash flows from operating activities
Net loss	$	(81,559	)	$	(41,821	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Loss on extinguishment of debt	—			29,157
Depreciation, depletion and amortization	143,624			115,905
Impairment	117,908			—
Accretion of firm transportation obligation	584			856
Derivative contracts:
Net losses (gains)	58,327			(827		)
Cash settlements, net	(10,279		)	5,790
Deferred income tax benefit	(42,452		)	(22,471		)
(Gain) loss on sales of assets, net	(56,775		)	293
Non-cash exploration expense	6,579			10,408
Non-cash interest expense	2,051			1,885
Share-based compensation (equity-classified)	1,651			3,771
Other, net	281			82
Changes in operating assets and liabilities, net	(40,747		)	26,723
Net cash provided by operating activities	99,193			129,751

Cash flows from investing activities
Acquisition, net	—			(358,239		)
Payments to settle working capital adjustments assumed in acquisition, net	—			(36,310		)
Capital expenditures - property and equipment	(350,580		)	(229,319		)
Proceeds from sales of assets, net	96,632			867
Net cash used in investing activities	(253,948		)	(623,001		)

Cash flows from financing activities
Proceeds from the issuance of preferred stock, net	313,646			—
Payments made to induce conversion of preferred stock	(3,368		)	—
Proceeds from the issuance of senior notes	—			775,000
Retirement of senior notes	—			(319,090		)
Proceeds from revolving credit facility borrowings	302,000			153,000
Repayment of revolving credit facility borrowings	(453,000		)	(86,000		)
Debt issuance costs paid	(151		)	(24,698		)
Dividends paid on preferred stock	(3,836		)	(3,412		)
Other, net	1,085			(110		)
Net cash provided by financing activities	156,376			494,690
Net increase in cash and cash equivalents	1,621			1,440
Cash and cash equivalents - beginning of period	23,474			17,650
Cash and cash equivalents - end of period	$	25,095		$	19,090

Supplemental disclosures:
Cash paid for:
Interest	$	47,034		$	23,215
Income taxes (net of refunds received)	$	100		$	—

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 June 30, 2014

(in thousands, except per share amounts)


1.	Organization

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


2.	Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2013. Operating results for the six months ended June 30, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014. Certain amounts for the 2013 period have been reclassified to conform to the current year presentation.

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

Management has evaluated all activities of the Company, through the date upon which our Condensed Consolidated Financial Statements were issued. As discussed in Note 3 below, the following events occurred subsequent to June 30, 2014 for which appropriate recognition or disclosure has been made in our Condensed Consolidated Financial Statements and Notes: (i) in July 2014 we entered into an agreement to acquire significant additional Eagle Ford acreage in Lavaca County, Texas, (ii) in July 2014, we received the arbitrator’s determination with respect to our Eagle Ford acquisition in 2013 (the “EF Acquisition”) and (iii) in July 2014, we completed a sale of rights to construct an oil gathering system in South Texas. Except for the aforementioned developments, management has concluded that no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to Condensed Consolidated Financial Statements.


3.	Acquisitions and Divestitures

Acquisitions

Undeveloped Eagle Ford Acreage

In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) Eagle Ford acres in Lavaca County, Texas for approximately $45 million, of which approximately $34 million will be paid at closing and the balance of approximately $11 million will be paid over time as a drilling carry. The transaction is expected to close in August 2014 and is subject to customary closing conditions.

EF Acquisition

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

these rights, which was recorded as a decrease to our purchase price for the EF Acquisition. Subsequent to the Acquisition Date and through December 31, 2013, we paid a total of $22.5 million, net to settle working capital adjustments assumed in the EF Acquisition.

Commencing December 2013, we were involved in an arbitration with Magnum Hunter Resources Corporation (“MHR”), the seller in our EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. Effective with the one-year anniversary of the Acquisition Date, we recorded a receivable for final purchase price adjustments representing management’s estimate of the outcome of the arbitration. On July 29, 2014, we received the arbitrator’s determination, which indicates that MHR is required to pay us approximately $31.0 million of purchase price adjustments and to transfer to us approximately $2.7 million of revenue suspense funds due to partners and royalty owners. The award is consistent with the estimate made by management. We are also entitled to interest on the funds since the Acquisition Date.

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



Assets
Oil and gas properties - proved	$	267,688
Oil and gas properties - unproved	119,709
Accounts receivable, net	107,345
Other assets	2,068
	496,810
Liabilities
Accounts payable and accrued expenses	94,771
Other liabilities	1,500
	96,271
Net assets acquired	$	400,539

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

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

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



	Periods Ended June 30, 2013
	Three Months			Six Months
Total revenues	$	113,735		$	222,799
Net loss attributable to common shareholders	$	(7,896	)	$	(23,412	)
Loss per share - basic and diluted	$	(0.12	)	$	(0.36	)

Divestitures

In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas and received proceeds of approximately $147 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with the buyer to provide us gathering and intermediate pipeline transportation services for a substantial portion of our South Texas crude oil and condensate production.

In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets (primarily natural gas) in Mississippi for gross cash proceeds of $72.7 million. The sale is expected to close in the third quarter of 2014 and we anticipate receiving approximately $71 million of proceeds, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 with respect to these assets.

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas and received proceeds of approximately $96 million. Concurrent with the sale, we entered into a long-term agreement with the buyer to provide us natural gas gathering and compression services for a substantial portion of our South Texas natural gas production. We realized a gain of $67.3 million of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period. We amortized $0.1 million and $0.2 million of the deferred gain during the three and six months ended June 30, 2014, respectively. As of June 30, 2014, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $10.0 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

4. Accounts Receivable and Major Customers

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



	As of
	June 30,			December 31,
	2014			2013
Customers	$	101,369		$	93,288
Joint interest partners	96,129			76,199
Other ¹	41,003			25,538
	238,501			195,025
Less: Allowance for doubtful accounts	(176		)	(622		)
	$	238,325		$	194,403

______________________

¹ Comprised substantially of amounts due from the seller and other parties for purchase price adjustments attributable to the EF Acquisition.

For the six months ended June 30, 2014, four customers accounted for $148.8 million, or approximately 55%, of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2014 were $48.4 million, $35.5 million, $34.0 million and $30.9 million or 18%, 13%, 13% and 11% of the consolidated total, respectively. As of June 30, 2014, $52.3 million, or approximately 52% of our consolidated accounts receivable from customers was related to these customers. For the six months ended June 30, 2013, four customers accounted for $93.1 million, or approximately 48% of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2013 were $31.3 million, $21.9 million, $20.5 million and $19.4 million or approximately 16%, 11%, 11% and 10% of the consolidated total, respectively. As of December 31, 2013, $50.7 million, or approximately 54% of our consolidated accounts receivable from customers, was related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by any of these customers.


5.	Derivative Instruments

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

Commodity Derivatives

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

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. A swaption contract gives our counterparties the option to enter into a fixed price swap with us at a future date. If the forward commodity price for the term of the swaption is higher than or equal to the swaption strike price on the exercise date, the counterparty will exercise its option to enter into a fixed price swap at the swaption strike price for the term of the swaption, at which point the contract functions as a fixed price swap. If the forward

commodity price for the term of the swaption is lower than the swaption strike price on the exercise date, the option expires and no fixed price swap is in effect.

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 June 30, 2014:



		Average
		Volume Per	Weighted Average Price			Fair Value
	Instrument	Day	Floor/Swap		Ceiling	Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Third quarter 2014	Collars	2,000	$	90.00	94.33	$	—	$	1,862
Fourth quarter 2014	Collars	2,000	$	90.00	94.33	—		1,487
First quarter 2015	Collars	4,000	$	87.50	94.66	—		2,284
Second quarter 2015	Collars	4,000	$	87.50	94.66	—		1,741
Third quarter 2015	Collars	3,000	$	86.67	94.73	—		1,002
Fourth quarter 2015	Collars	3,000	$	86.67	94.73	—		719
Third quarter 2014	Swaps	10,000	$	93.21		—		10,250
Fourth quarter 2014	Swaps	11,000	$	93.45		—		8,489
First quarter 2015	Swaps	9,000	$	91.81		—		6,227
Second quarter 2015	Swaps	9,000	$	91.81		—		4,637
Third quarter 2015	Swaps	8,000	$	91.06		—		3,478
Fourth quarter 2015	Swaps	8,000	$	91.06		—		2,615
First quarter 2016	Swaps	2,000	$	90.43		—		418
Second quarter 2016	Swaps	2,000	$	90.43		—		218
Third quarter 2016	Swaps	2,000	$	90.43		—		75
Fourth quarter 2016	Swaps	2,000	$	90.43		17		—
First quarter 2015	Swaptions	1,000	$	88.00		—		896
Second quarter 2015	Swaptions	1,000	$	88.00		—		896
Third quarter 2015	Swaptions	1,000	$	88.00		—		896
Fourth quarter 2015	Swaptions	1,000	$	88.00		—		895

Natural Gas:		(in MMBtu)	($/MMBtu)
Third quarter 2014	Swaps	15,000	$	4.10		—		455
Fourth quarter 2014	Swaps	5,000	$	4.50		10		—
First quarter 2015	Swaps	5,000	$	4.50		—		16
Settlements to be paid in subsequent period						—		3,277

Interest Rate Swaps

As of June 30, 2014, 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					Six Months Ended
	June 30,					June 30,
	2014			2013		2014			2013
Impact by contract type:
Commodity contracts	$	(42,665	)	$	8,588	$	(58,327	)	$	827
Interest rate contracts	—			—		—			—
	$	(42,665	)	$	8,588	$	(58,327	)	$	827
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	(7,222	)	$	2,233	$	(10,279	)	$	5,790
Interest rate contract settlements	—			—		—			—
	(7,222		)	2,233		(10,279		)	5,790
Gains (losses) attributable to:
Commodity contracts	(35,443		)	6,355		(48,048		)	(4,963		)
Interest rate contracts	—			—		—			—
	(35,443		)	6,355		(48,048		)	(4,963		)
	$	(42,665	)	$	8,588	$	(58,327	)	$	827

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

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
		June 30, 2014				December 31, 2013
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	—	$	44,298	$	3,830	$	10,141
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		—		44,298		3,830		10,141

Commodity contracts	Derivative assets/liabilities - noncurrent	—		8,508		1,552		—
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		—		8,508		1,552		—
		$	—	$	52,806	$	5,382	$	10,141

As of June 30, 2014, our commodity derivative portfolio was in a net liability position. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with five of those counterparties. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions.


6.	Property and Equipment

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



	As of
	June 30,			December 31,
	2014			2013
Oil and gas properties:
Proved	$	440,606		$	460,255
Unproved	102,492			101,520
Total oil and gas properties	543,098			561,775
Other property and equipment:
Wells equipment and facilities	2,575,966			2,593,700
Support equipment	22,591			21,513
Total other property and equipment	2,598,557			2,615,213
	3,141,655			3,176,988
Accumulated depreciation, depletion and amortization	(933,901		)	(939,684		)
	$	2,207,754		$	2,237,304

In June 2014, we recognized a $117.9 million impairment of our Selma Chalk assets in Mississippi triggered by the expected disposition of these properties. The fair value of these properties, after the impairment, has been reclassified from Property and equipment to Assets held for sale which is presented as a component of current assets on our Condensed Consolidated Balance Sheets. In addition, liabilities associated with these assets representing asset retirement obligations (“AROs”), have been reclassified from Other liabilities (noncurrent) to Accounts payable and accrued expenses which is presented as a component of current liabilities.


7.	Long-Term Debt

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



	As of
	June 30,		December 31,
	2014		2013
Revolving credit facility	$	55,000	$	206,000
Senior notes due 2019	300,000		300,000
Senior notes due 2020	775,000		775,000
	$	1,130,000	$	1,281,000

Revolving Credit Facility

The revolving credit facility (the “Revolver”) provides for a $450 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $150 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. Upon the expected closing of the sale of our Selma Chalk assets in the third quarter of 2014, the borrowing base will be reduced from $475 million to $437.5 million. The next semi-annual redetermination is scheduled for November 2014. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $1.7 million outstanding as of June 30, 2014. As of June 30, 2014, our available borrowing capacity under the Revolver was $393.3 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of June 30, 2014, the actual interest rate on the outstanding borrowings under the Revolver was 1.6875% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.50%. Commitment fees are charged at 0.375% to 0.500% on

the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2014, commitment fees were being charged at a rate of 0.375%.

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

The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The 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.

2019 Senior Notes

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

2020 Senior Notes

The 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on June 15 and December 15 of each year. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

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


8.	Income Taxes

We recognized an income tax benefit for the three and six months ended June 30, 2014 at an effective rate of 34.2%. The effective tax rate reflects the adverse effect of losses incurred in certain jurisdictions for which we may not realize a tax benefit and have therefore recorded a valuation allowance against the related deferred tax assets. The impact of recording a valuation allowance during the period resulted in a decrease to both the total tax benefit being recognized and the overall effective tax rate. Due to the loss incurred during the three and six months ended June 30, 2013, we recognized an income tax benefit at an effective rate of 35.0%. The income tax benefit included the effect of deferred tax asset valuation allowance due primarily to the inability to recognize tax benefits for certain state net operating losses.


9.	Additional Balance Sheet Detail

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



	As of
	June 30,		December 31,
	2014		2013
Other current assets:
Tubular inventory and well materials	$	2,122	$	2,271
Prepaid expenses	3,409		3,653
Other	100		—
	$	5,631	$	5,924
Other assets:
Debt issuance costs	$	28,339	$	30,239
Assets of supplemental employee retirement plan (“SERP”)	3,951		3,734
Other	563		562
	$	32,853	$	34,535
Accounts payable and accrued liabilities:
Trade accounts payable	$	112,835	$	120,278
Drilling and other lease operating costs	42,923		51,529
Royalties	45,089		39,929
Production and franchise taxes	5,198		5,338
Compensation - related	10,003		8,584
Interest	15,602		15,718
Preferred stock dividends	1,329		1,725
Liabilities associated with assets held for sale	1,224		—
Other	6,051		4,903
	$	240,254	$	248,004
Other liabilities:
Deferred gain on sale of assets	$	9,989	$	—
Firm transportation obligation	12,533		13,245
Asset retirement obligations	5,669		6,437
Defined benefit pension obligations	1,491		1,579
Postretirement health care benefit obligations	1,112		1,023
Deferred compensation - SERP obligations and other	4,216		3,883
Other	9,891		7,219
	$	44,901	$	33,386


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 June 30, 2014, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

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



	As of
	June 30, 2014				December 31, 2013
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	315,000	$	300,000	$	307,500	$	300,000
Senior Notes due 2020	864,125		775,000		837,969		775,000
	$	1,179,125	$	1,075,000	$	1,145,469	$	1,075,000

Recurring Fair Value Measurements

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



	As of June 30, 2014
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	—		$	—		$	—		$	—
Commodity derivative assets - noncurrent	—			—			—			—
Assets of SERP	3,951			3,951			—			—
Liabilities:
Commodity derivative liabilities - current	(44,298		)	—			(44,298		)	—
Commodity derivative liabilities - noncurrent	(8,508		)	—			(8,508		)	—
Deferred compensation - SERP obligations	(4,211		)	(4,211		)	—			—



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

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the six months ended June 30, 2014 and 2013.

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

•

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


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


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

Non-Recurring Fair Value Measurements

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

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


11.	Commitments and Contingencies

Drilling and Completion Commitments

We have agreements to purchase oil and gas well drilling and well completion services from third parties with remaining terms of up to 14 months. The well drilling agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their original terms. The amount of penalty is based on the number of days remaining in the contractual term. As of June 30, 2014, the penalty amount would have been $13.3 million if we had terminated our agreements on that date.

Other Commitments

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

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

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

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of June 30, 2014. In addition to the reserve for litigation, we maintain a suspense account which includes approximately $2.2 million representing the excess of

revenues received over costs incurred attributable to these properties. As of June 30, 2014, we also have AROs of approximately $5.7 million attributable to the plugging of abandoned wells.


12.	Shareholders’ Equity

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



	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			June 30,
	2013			Net Loss			Offering		Declared ¹			Changes ²			2014
Preferred stock ³	$	1,150		$	—		$	3,250	$	—		$	(262	)	$	4,138
Common stock ³	466			—			—		—			46			512
Paid-in capital ³	891,351			—			310,396		—			2,477			1,204,224
Accumulated deficit ³	(104,180		)	(81,559		)	—		(3,440		)	(3,368		)	(192,547		)
Deferred compensation obligation	2,792			—			—		—			209			3,001
Accumulated other comprehensive income ⁴	267			—			—		—			49			316
Treasury stock	(3,042		)	—			—		—			(210		)	(3,252		)
	$	788,804		$	(81,559	)	$	313,646	$	(3,440	)	$	(1,059	)	$	1,016,392

	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			June 30,
	2012			Net Loss			Offering		Declared ¹			Changes ²			2013
Preferred stock	$	1,150		$	—		$	—	$	—		$	—		$	1,150
Common stock	364			—			—		—			101			465
Paid-in capital	849,046			—			—		—			45,401			894,447
Retained earnings	45,790			(41,821		)	—		(3,450		)	—			519
Deferred compensation obligation	3,111			—			—		—			(448		)	2,663
Accumulated other comprehensive loss ⁴	(982		)	—			—		—			38			(944		)
Treasury stock	(3,363		)	—			—		—			450			(2,913		)
	$	895,116		$	(41,821	)	$	—	$	(3,450	)	$	45,542		$	895,387

______________________

¹ Includes dividends of $300.00 per share of our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”).

² Includes equity-classified share-based compensation of $1,651 and $3,771 for the six months ended June 30, 2014 and 2013.

³ A total of 2,620 shares, or 262,012 depositary shares, of the Series A Preferred Stock were converted into 4,366,872 shares of our common stock during the six months ended June 30, 2014. We made payments of $3.4 million to induce the conversion of 2,593 of these shares.

⁴ The Accumulated other comprehensive income (loss) (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the six months ended June 30, 2014 and 2013 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $75 and $58 and are presented above net of taxes of $26 and $20.

In June 2014, we completed a private offering of 3,250,000 depositary shares each representing a 1/100^th interest in a share, or 32,500 shares, of our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”), that provided approximately $314 million of proceeds, net of underwriting fees and issuance costs.

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

Each share of the Series B Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $18.34 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 545.17 shares of our common stock for each share of the Series B Preferred Stock. The initial conversion price represents a premium of 30 percent relative to the last reported sales price of $14.11 per common share prior to the offering of the Series B Preferred Stock. The Series B Preferred Stock is not redeemable by us or the holders at any time. At any time on or after July 15, 2019, we may, at our option, cause all outstanding shares of the Series B Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the Series B Preferred Stock

upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.


13.	Share-Based Compensation

The Penn Virginia Corporation 2013 Amended and Restated Long-Term Incentive Plan (the “LTI Plan”) permits the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. We recognize compensation expense related to our LTI Plan in the General and administrative caption on our Condensed Consolidated Statements of Operations.

With the exception of performance-based restricted stock units (“PBRSUs”), all of the awards issued under our LTI Plan are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The compensation cost attributable to these awards is measured at the grant date and recognized over the applicable vesting period as a non-cash item of expense. Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Accounts payable and accrued liabilities (current portion) and Other liabilities (noncurrent portion) captions on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period and recognized based on the period of time that has elapsed during each of the individual performance periods.

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



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Equity-classified awards:
Stock option awards	$	329	$	1,114	$	790	$	1,906
Common, deferred and restricted stock and stock unit awards	497		1,572		861		1,865
	826		2,686		1,651		3,771
Liability-classified awards	1,047		435		6,992		449
	$	1,873	$	3,121	$	8,643	$	4,220


14.	Restructuring and Exit Activities

We have a contractual commitment for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale of our natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production to satisfy this commitment. We recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract. The activity summarized below includes contractual payments on our obligations as well as the recognition of accretion expense and adjustments associated with changes in estimates.

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Balance at beginning of period	$	15,806		$	16,972		$	16,090		$	17,263
Employee, office and other costs accrued, net	(4		)	—			9			—
Accretion of firm transportation obligation	230			649			584			856
Cash payments, net	(473		)	(944		)	(1,124		)	(1,442		)
Balance at end of period	$	15,559		$	16,677		$	15,559		$	16,677

Restructuring charges are included in the General and administrative caption on our Condensed Consolidated Statements of Operations. The accretion of the firm transportation obligation, net of any recoveries from the periodic sale of our contractual capacity, is charged as an offset to Other revenue.

The current portion of our restructuring and exit cost obligations is included in the Accounts payable and accrued liabilities caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of June 30, 2014, $3.0 million of the total obligations are classified as current while the remaining $12.6 million are classified as noncurrent.


15.	Interest Expense

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Interest on borrowings and related fees	$	23,778		$	20,902		$	46,918		$	34,485
Accretion of original issue discount ¹	—			110			—			431
Amortization of debt issuance costs	1,039			829			2,051			1,454
Capitalized interest ²	(1,588		)	(33		)	(3,206		)	(83		)
	$	23,229		$	21,808		$	45,763		$	36,287

_____________________

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

² The increase in capitalized interest in 2014 is attributable to a significant increase in qualifying activities that are in process to bring our Eagle Ford unproved and proved undeveloped properties, including those acquired in the EF Acquisition, into production.


16.	Earnings per Share

The following table provides a reconciliation of the components used in the calculation of basic and diluted earnings per share for the periods presented:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net loss	$	(100,784	)	$	(25,438	)	$	(81,559	)	$	(41,821	)
Less: Preferred stock dividends ¹	(1,718		)	(1,725		)	(3,440		)	(3,450		)
Less: Induced conversion of preferred stock	(3,368		)	—			(3,368		)	—
Net loss attributable to common shareholders - Basic and diluted	$	(105,870	)	$	(27,163	)	$	(88,367	)	$	(45,271	)

Weighted-average shares - Basic	66,514			62,899			66,065			59,141
Effect of dilutive securities ²	—			—			—			—
Weighted-average shares - Diluted	66,514			62,899			66,065			59,141

_______________________

1 Preferred stock dividends were excluded for diluted earnings per share as the assumed conversion of the outstanding Series A Preferred Stock would have been anti-dilutive. There were no dividends declared on the Series B Preferred stock during the three and six months ended June 30, 2014.

² For the three and six months ended June 30, 2014, approximately 18.8 million and 17.2 million, respectively, potentially dilutive securities, including the Series A and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share. For the three and six months ended June 30, 2013, approximately 19.2 million and 0.1 million, respectively, potentially dilutive securities, including the Series A Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

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 oil and gas companies;


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


•	leasehold terms expiring before production can be established;


•	environmental obligations, costs and liabilities that are not covered by an effective indemnity or insurance;


•	the timing of receipt of necessary regulatory permits;


•	the effect of commodity and financial derivative arrangements;


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


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


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


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


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


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


•	other risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2013.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. 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,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Certain year-over-year changes are presented as not meaningful, or “NM,” where disclosure of the actual value does not otherwise enhance the analysis. Also, due to the combination of different units of volumetric measure and the number of decimal places presented, certain results may not calculate explicitly from the values presented in the tables.

Overview of Business

We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various onshore regions of the United States. Our current operations consist primarily of the drilling of unconventional horizontal development wells and are currently concentrated in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma, the Haynesville Shale and Cotton Valley in East Texas and the Selma Chalk in Mississippi, the latter of which we have agreed to sell. As of December 31, 2013, we had proved oil and gas reserves of approximately 136 million barrels of oil equivalent, or MMBOE (approximately 122 MMBOE excluding our Selma Chalk assets in Mississippi).

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Total production (MBOE)	1,983			1,748			3,885			3,175
Daily production (BOEPD)	21,786			19,209			21,461			17,542
Crude oil and NGL production (MBbl)	1,379.6			1,118.4			2,682.6			1,951.5
Crude oil and NGL production as a percent of total	70		%	64		%	69		%	61		%
Product revenues, as reported	$	136,429		$	109,734		$	269,581		$	191,958
Product revenues, as adjusted for derivatives	$	129,207		$	111,967		$	259,302		$	197,748
Crude oil and NGL revenues as a percent of total, as reported	88		%	86		%	87		%	86		%
Realized prices:
Crude oil ($/Bbl)	$	100.16		$	101.23		$	99.16		$	102.89
NGL ($/Bbl)	$	30.85		$	28.10		$	35.71		$	29.21
Natural gas ($/Mcf)	$	4.51		$	4.12		$	4.78		$	3.76
Aggregate ($/BOE)	$	68.81		$	62.78		$	69.40		$	60.46
Production and lifting costs ($/BOE):
Lease operating	$	6.25		$	4.94		$	5.87		$	5.18
Gathering, processing and transportation	1.78			1.70			1.67			2.07
Production and ad valorem taxes ($/BOE)	3.79			3.99			3.81			4.07
General and administrative ($/BOE) ¹	6.54			7.17			5.89			7.05
Total operating costs ($/BOE)	$	18.36		$	17.80		$	17.24		$	18.37
Depreciation, depletion and amortization ($/BOE)	$	36.03		$	36.80		$	36.97		$	36.51
Cash provided by operating activities	$	32,633		$	84,136		$	99,193		$	129,751
Cash paid for capital expenditures	$	190,776		$	143,346		$	350,580		$	229,319
Cash and cash equivalents at end of period							$	25,095		$	19,090
Debt outstanding, net of discounts, at end of period							$	1,130,000		$	1,142,000
Credit available under revolving credit facility at end of period ²							$	393,346		$	279,968
Net development wells drilled	15.0			10.8			28.8			19.3
Net exploratory wells drilled	—			—			—			—

_______________________

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.42 and $0.42 for the three and six months ended June 30, 2014 and $1.54 and $1.19 for the three and six months ended June 30, 2013 and liability-classified share-based compensation of $0.53 and $1.80 for the three and six months ended June 30, 2014 and $0.25 and $0.14 for the three and six months ended June 30, 2013.

² As reduced by outstanding borrowings and letters of credit and limited by financial covenants, if applicable.

In the three months ended June 30, 2014, our crude oil and NGL production increased to 70 percent of our total production continuing a trend consistent with our liquids-focused strategy. Our cash margin, or aggregate realized prices less total operating costs excluding equity-classified and liability-classified share-based compensation, increased $5.47 per barrel of oil equivalent, or BOE, or 12 percent, to $50.45 per BOE for the three months ended June 30, 2014 from $44.98 per BOE for the corresponding period in 2013. The cash margin increased $10.07 per BOE, or 24 percent, to $52.16 per BOE when compared to $42.09 per BOE for the six months ended June 30, 2013. The higher cash margins are attributable primarily to higher liquids production and higher NGL and natural gas prices compared to the corresponding periods of the prior year. Consistent with our growth in cash margins, our cash from operating activities, excluding working capital changes, increased approximately $37 million, or 36 percent, for the six months ended June 30, 2014 compared the corresponding period of the prior year.

Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. Since our initial acquisition in this region in 2010, we have drilled and turned in line 219 gross (141.5 net) wells through July 25, 2014. We are currently operating a total of six drilling rigs in the Eagle Ford and have plans in place to increase the total to eight rigs by the end of September 2014. Our capital program, of which approximately 98 percent is dedicated to the Eagle Ford, is being financed with a combination of cash from operating activities, the sale of non-core assets, borrowings under our revolving credit facility, or the Revolver, and our recent preferred equity offering.

Key Developments

The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) drilling results and future development plans in the Eagle Ford, (ii) the acquisition of additional Eagle Ford acreage, (iii) recent preferred stock transactions, (iv) the sale of Mississippi assets, South Texas oil gathering rights and natural gas gathering and gas lift assets and (v) the resolution of arbitration related to our Eagle Ford acquisition in 2013.

Drilling Results and Future Development Plans for the Eagle Ford

During the three months ended June 30, 2014, we operated six drilling rigs and completed 27 gross (15.0 net) wells in the Eagle Ford. Our Eagle Ford production was 15,618 net barrels of oil equivalent per day, or BOEPD, during the three months ended June 30, 2014 with oil comprising 11,744 BOPD, or 75 percent and NGLs and natural gas comprising approximately 13 percent and 12 percent. Our Eagle Ford oil production was two percent higher than 11,511 BOPD in the first quarter of 2014. In the Eagle Ford, we have a total of 219 gross (141.5 net) producing wells, 11 gross (6.3 net) wells completing, 11 gross (5.0 net) wells waiting on completion and six gross (4.6 net) wells being drilled as of July 25, 2014.

We intend to add a seventh rig to our Eagle Ford drilling program in August 2014 and an eighth rig in September 2014. We have increased the drilling and completion component of our capital expenditures program accordingly. As a result of the additional rigs, we expect to turn in line 68 gross (39.0 net) wells during the remainder of 2014, for a total of 111 (67.0 net) operated wells, excluding shallow wells, being turned in line during 2014, along with a production contribution associated with the seventh and eighth rigs of 700 to 800 MBOE in the fourth quarter of 2014.

Through July 25, 2014 we have tested three Upper Eagle Ford (Marl) and for the remainder of 2014, we have 19 additional Upper Eagle Ford wells planned to spud, with eight of those scheduled as development wells in the same area as our three initial test wells.

Acquisition of Additional Eagle Ford Acreage

In July 2014, we entered into a definitive agreement to acquire approximately 13,125 gross (11,660 net) acres in Lavaca County, Texas, the vast majority of which are in the “volatile oil window” of the Eagle Ford, for approximately $45 million, of which approximately $34 million will be paid at closing and the balance of approximately $11 million will be paid over time as a drilling carry. The transaction is expected to close in August 2014 and is subject to customary closing conditions. The transaction, combined with recent leasing, will bring our total Eagle Ford acreage position to approximately 143,200 gross (102,000 net) acres which to a large extent are contiguous. The acquired acreage is adjacent to our Shiner area, most of which we expect will be prospective in the Upper Eagle Ford.

Preferred Stock Offering and Induced Conversion of Outstanding Preferred Stock

In June 2014, we completed a private offering of 3,250,000 depositary shares each representing 1/100th interest in a share of our 6% Series B Convertible Perpetual Preferred Stock, or the Series B Preferred Stock, that provided approximately $314 million of proceeds, net of underwriting fees and issuance costs. Concurrently, we paid $3.4 million to induce the conversion of 2,593 shares, or 259,262 depositary shares, of our 6% Series A Convertible Perpetual Preferred Stock, or the Series A Preferred Stock. A total of 4.3 million shares of our common stock were issued in connection with the induced

conversion of the Series A Preferred Stock. Subsequent to June 30, 2014, an additional 93 shares of the Series A Preferred Stock have been converted resulting in issuance of an additional 1.6 million shares of our common stock.

Sale of Mississippi Assets

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

Sale of South Texas Natural Gas Gathering and Gas Lift Assets

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas and received proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with the buyer to provide us natural gas gathering and compression services for a substantial portion of our South Texas natural gas production. We realized a gain of $67.3 million of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period.

Arbitration Developments

Commencing December 2013, we were involved in an arbitration with Magnum Hunter Resources Corporation, or MHR, the seller in our 2013 Eagle Ford property acquisition, or EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. Effective with the one-year anniversary of the acquisition date, we recorded a receivable for final purchase price adjustments representing management’s estimate of the outcome of the arbitration. On July 29, 2014, we received the arbitrator’s determination, which indicates that MHR is required to pay us approximately $31.0 million of purchase price adjustments and to transfer to us approximately $2.7 million of revenue suspense funds due to partners and royalty owners. The award is consistent with the estimate made by management. We are also entitled to interest on the funds since the acquisition date.

Results of Operations

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

Production

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



Crude oil	Three Months Ended				Three Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	1,068.7	798.3	270.5		11,744.2	8,772.1	2,972.1		34	%
East Texas	13.6	15.0	(1.4	)	149.5	164.4	(14.9	)	(9	)%
Mid-Continent	35.1	42.2	(7.0	)	386.1	463.3	(77.2	)	(17	)%
Mississippi	1.6	2.8	(1.1	)	18.0	30.5	(12.5	)	(41	)%
Appalachia	—	—	—		—	—	—		—	%
	1,119.1	858.2	260.9		12,297.8	9,430.3	2,867.5		30	%



NGLs	Three Months Ended				Three Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	189.7	133.6	56.1		2,084.2	1,468.0	616.3		42	%
East Texas	33.5	46.9	(13.5	)	367.8	515.7	(147.9	)	(29	)%
Mid-Continent	37.4	79.8	(42.4	)	410.6	876.7	(466.1	)	(53	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	—	—		—	—	—		—	%
	260.5	260.3	0.2		2,862.6	2,860.4	2.3		—	%



Natural gas	Three Months Ended				Three Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	977	702	275		10.7	7.7	3.0		39	%
East Texas	1,037	1,160	(123	)	11.4	12.8	(1.4	)	(11	)%
Mid-Continent	531	727	(196	)	5.8	8.0	(2.1	)	(27	)%
Mississippi	1,036	1,151	(116	)	11.4	12.7	(1.3	)	(10	)%
Appalachia	36	37	(1	)	0.4	0.4	—		(3	)%
	3,618	3,778	(160	)	39.8	41.5	(1.8	)	(4	)%



Combined total	Three Months Ended				Three Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	1,421	1,049	372		15,618.2	11,525.5	4,092.7		36	%
East Texas	220	255	(35	)	2,417.1	2,805.2	(388.1	)	(14	)%
Mid-Continent	161	243	(82	)	1,769.8	2,671.3	(901.5	)	(34	)%
Mississippi	174	195	(20	)	1,914.8	2,138.9	(224.0	)	(10	)%
Appalachia	6	6	—		66.5	68.3	(1.8	)	(3	)%
	1,983	1,748	235		21,786.4	19,209.2	2,577.3		13	%

Total production increased during the three months ended June 30, 2014 compared to the corresponding period of 2013 due primarily to production from the properties acquired and developed from the EF Acquisition and the continued expansion of our legacy development program in South Texas. The increase was partially offset by natural production declines in our East Texas, Mid-Continent and Mississippi regions. Approximately 70% of total production during the three months ended June 30, 2014 was attributable to oil and NGLs, which represents an increase of approximately 30% over the prior year period. During

the three months ended June 30, 2014, our Eagle Ford production represented approximately 72% of our total production compared to approximately 60% from this play during the corresponding period of 2013.

Product Revenues and Prices

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



Crude oil	Three Months Ended								Three Months Ended
	June 30,					Favorable			June 30,				Favorable
	2014		2013			(Unfavorable)			2014		2013		(Unfavorable)
									($ per Bbl)
Texas
South Texas	$	107,208	$	81,312		$	25,896		$	100.31	$	101.86	$	(1.55	)
East Texas	1,373		1,471			(98		)	100.89		98.31		2.58
Mid-Continent	3,351		3,795			(444		)	95.38		90.01		5.37
Mississippi	158		291			(133		)	96.64		105.02		(8.38		)
Appalachia	—		(2		)	2			—		—		NM
	$	112,090	$	86,867		$	25,223		$	100.16	$	101.23	$	(1.07	)



NGLs	Three Months Ended							Three Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	4,827	$	3,220	$	1,607		$	25.45	$	24.10	$	1.35
East Texas	1,403		1,436		(33		)	41.92		30.60		11.32
Mid-Continent	1,807		2,657		(850		)	48.36		33.30		15.06
Mississippi	—		—		—			—		—		—
Appalachia	—		—		—			—		—		—
	$	8,037	$	7,313	$	724		$	30.85	$	28.10	$	2.75



Natural gas	Three Months Ended							Three Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	4,490	$	2,733	$	1,757		$	4.59	$	3.89	$	0.70
East Texas	4,514		4,001		513			4.35		3.45		0.90
Mid-Continent	2,371		3,873		(1,502		)	4.46		5.33		(0.87		)
Mississippi	4,797		4,213		584			4.63		3.66		0.97
Appalachia	130		734		(604		)	3.58		NM		NM
	$	16,302	$	15,554	$	748		$	4.51	$	4.12	$	0.39



Combined total	Three Months Ended							Three Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per BOE)
Texas
South Texas	$	116,525	$	87,265	$	29,260		$	81.99	$	83.20	$	(1.22	)
East Texas	7,290		6,908		382			33.14		27.06		6.08
Mid-Continent	7,529		10,325		(2,796		)	46.75		42.47		4.28
Mississippi	4,955		4,504		451			28.44		23.14		5.30
Appalachia	130		732		(602		)	21.47		NM		NM
	$	136,429	$	109,734	$	26,695		$	68.81	$	62.78	$	6.04

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



	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	26,420		$	(1,197	)	$	25,223
NGL	6			718			724
Natural gas	(658		)	1,406			748
	$	25,768		$	927		$	26,695

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 June 30, 2014 and 2013, we paid $7.2 million and received $2.2 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
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Crude oil revenues as reported	$	112,090		$	86,867		$	25,223		29	%
Cash settlements of crude oil derivatives, net	(6,087		)	2,468			(8,555		)	NM
	$	106,003		$	89,335		$	16,668		19	%

Crude oil prices per Bbl, as reported	$	100.16		$	101.23		$	(1.06	)	(1	)%
Cash settlements of crude oil derivatives per Bbl	(5.44		)	2.88			(8.31		)	NM
	$	94.72		$	104.11		$	(9.37	)	(9	)%

Natural gas revenues as reported	$	16,302		$	15,554		$	748		5	%
Cash settlements of natural gas derivatives, net	(1,135		)	(235		)	(900		)	383	%
	$	15,167		$	15,319		$	(152	)	(1	)%

Natural gas prices per Mcf, as reported	$	4.51		$	4.12		$	0.39		9	%
Cash settlements of natural gas derivatives per Mcf	(0.31		)	(0.06		)	(0.25		)	417	%
	$	4.20		$	4.06		$	0.14		3	%

Other Revenues

Other income includes gathering, transportation, compression and water supply and disposal fees, net of marketing and related expenses. The increase during the three months ended June 30, 2014 was attributable income related to water supply and disposal.

Production and Lifting Costs



	Three Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Lease operating	$	12,403	$	8,629	$	(3,774	)	(44	)%
Per unit of production ($/BOE)	$	6.25	$	4.94	$	(1.31	)	(27	)%

Lease operating expense increased during the three months ended June 30, 2014 due primarily to higher chemical, water disposal and labor costs associated primarily with the expansion of operations in the South Texas region. In addition we incurred higher compression costs attributable to higher natural gas production in the South Texas region.



	Three Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Gathering, processing and transportation	$	3,526	$	2,980	$	(546	)	(18	)%
Per unit of production ($/BOE)	$	1.78	$	1.70	$	(0.08	)	(5	)%

Gathering, processing and transportation charges decreased during the three months ended June 30, 2014, due primarily to lower natural gas and NGL production volume in our East Texas, Mid-Continent and Mississippi regions. The decrease was offset partially by higher gathering charges for natural gas and NGL production in the South Texas region.



	Three Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	5,524		$	4,629		$	(895	)	(19	)%
Ad valorem taxes	1,986			2,347			361			15	%
	$	7,510		$	6,976		$	(534	)	(8	)%
Per unit production ($/BOE)	$	3.79		$	3.99		$	0.20		5	%
Production/severance tax rate as a percent of product revenue	4.0		%	4.2		%

Production taxes increased during the three months ended June 30, 2014 due primarily to the higher level of production in the South Texas region, partially offset by severance tax audit refunds for natural gas production in Mississippi.

General and Administrative

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



	Three Months Ended
	June 30,					Favorable
	2014			2013		(Unfavorable)			% Change
General and administrative expenses	$	11,846		$	10,129	$	(1,717	)	(17	)%
Share-based compensation (liability-classified)	1,047			435		(612		)	NM
Share-based compensation (equity-classified)	826			2,686		1,860			69	%
EF Acquisition-related transaction costs	—			2,396		2,396			NM
EF Acquisition-related arbitration and other costs	380			—		(380		)	NM
ERP system development costs	744			10		(734		)	(7,340	)%
Restructuring expenses	(3		)	—		3			NM
	$	14,840		$	15,656	$	816		5	%
Per unit of production ($/BOE)	$	7.48		$	8.96	$	1.48		17	%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	6.54		$	7.17	$	0.63		9	%
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	5.97		$	5.79	$	(0.18	)	(3	)%

On an absolute and unit of production basis, our general and administrative expenses, excluding liability and equity-classified share-based compensation increased marginally during the three months ended June 30, 2014 compared to the 2013 period reflecting higher employee benefits charges and the overall growth in scale of our operations. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the increase in fair value of the 2012 through 2014 PBRSU grants. The increase in the fair value of the PBRSUs is attributable to our common stock performance relative to a defined peer group. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the three months ended June 30, 2014 due primarily to fewer employees receiving grants. In 2013, we incurred transaction costs associated with the EF Acquisition including advisory, legal, due diligence and other professional fees. In 2014, we incurred costs including legal and litigation support fees attributable to our ongoing arbitration with the seller from the EF Acquisition transaction. In the three months ended June 30, 2014, we also incurred certain costs not eligible for capitalization, including post-implementation support and training with respect to our recently completed ERP system replacement.

Exploration

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



	Three Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)		% Change
Unproved leasehold amortization	$	3,285	$	5,146	$	1,861	36	%
Geological and geophysical costs	80		1,817		1,737		96	%
Other, primarily delay rentals	8		882		874		99	%
	$	3,373	$	7,845	$	4,472	57	%

Unproved leasehold amortization decreased during the three months ended June 30, 2014 due primarily to the classification of our unproved property in the Eagle Ford as a “significant leasehold” effective July 1, 2013. Accordingly, our unproved acreage in this region is no longer subject to systematic amortization. Geological and geophysical costs decreased due to lower seismic data acquisition costs in the current year period. Delay rentals decreased as the prior year period included charges attributable to undeveloped acreage acquired in connection with the EF Acquisition.

Depreciation, Depletion and Amortization (DD&A)

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



	Three Months Ended
	June 30,					Favorable
	2014			2013		(Unfavorable)			% Change
DD&A expense	$	71,437		$	64,329	$	(7,108	)	(11	)%
DD&A rate ($/BOE)	$	36.03		$	36.80	$	0.77		2	%

	Production			Rates		Total
DD&A variance due to:	$	(8,631	)	$	1,523	$	(7,108	)

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

Impairments

In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets (primarily natural gas) in Mississippi for gross cash proceeds of $72.7 million. The sale is expected to close in the third quarter of 2014 and we anticipate receiving approximately $71.0 million of proceeds, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 with respect to these assets.

Interest Expense

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



	Three Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Interest on borrowings and related fees	$	23,778		$	20,902		$	(2,876	)	(14	)%
Accretion of original issue discount	—			110			110			100	%
Amortization of debt issuance costs	1,039			828			(211		)	(25	)%
Capitalized interest	(1,588		)	(32		)	1,556			4,863	%
	$	23,229		$	21,808		$	(1,421	)	(7	)%
Weighted-average debt outstanding	$	1,303,000		$	1,028,688
Weighted average interest rate	7.62		%	8.49		%

Interest expense increased during the three months ended June 30, 2014 due primarily to higher overall weighted-average debt outstanding attributable to the issuance of the 8.5% Senior Notes due 2020, or 2020 Senior Notes, in April 2013, and higher average outstanding borrowings under the Revolver. The increase in interest expense was partially offset by higher capitalized interest resulting from the significant increase in the value of our proved undeveloped and unproved properties following the EF Acquisition and the absence of accretion of original issue discount attributable to the 10.375% Senior Notes due 2016, or 2016 Senior Notes which were retired in connection with a tender offer and a redemption, or the Tender Offer and the Redemption in May 2013. The weighted-average interest rate declined during the three months ended June 30, 2014 due

primarily to the replacement of the 2016 Senior Notes with the 2020 Senior Notes as well as borrowings under the Revolver, which carry lower interest rates.

Loss on Extinguishment of Debt

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

Derivatives

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



	Three Months Ended
	June 30,					Favorable
	2014			2013		(Unfavorable)			% Change
Oil and gas derivatives settled	$	(7,222	)	$	2,233	$	(9,455	)	(423	)%
Oil and gas derivatives loss	(35,443		)	6,355		(41,798		)	658	%
	$	(42,665	)	$	8,588	$	(51,253	)	80	%

We paid settlements of $6.1 million for crude oil derivatives and $1.1 million for natural gas derivatives during the three months ended June 30, 2014 and received settlements of $2.4 million from crude oil derivatives and paid settlements of $0.2 million for natural gas derivatives during the three months ended June 30, 2013.

Income Taxes



	Three Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)		% Change
Income tax benefit	$	56,716		$	13,682		$	43,034	315	%
Effective tax rate	36.0		%	35.0		%

We recognized income tax benefit for the three months ended June 30, 2014 and 2013 at effective tax rates of 36.0% and 35.0%, respectively. The effective tax rate reflects the adverse effect of losses incurred in certain jurisdictions for which we may not realize a tax benefit and have therefore recorded a valuation allowance against the related deferred tax assets. Additionally, our effective tax rate is also adversely impacted by the amount of losses in certain subsidiaries relative to taxable income of the Company.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

Production

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



Crude oil	Six Months Ended				Six Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	2,104.8	1,328.2	776.6		11,628.6	7,337.8	4,290.7		58	%
East Texas	26.4	31.6	(5.1	)	146.0	174.4	(28.4	)	(16	)%
Mid-Continent	59.6	90.4	(30.8	)	329.3	499.7	(170.3	)	(34	)%
Mississippi	4.2	6.8	(2.6	)	23.5	37.6	(14.2	)	(38	)%
Appalachia	—	0.1	(0.1	)	—	0.8	(0.8	)	(100	)%
	2,195.0	1,457.1	737.9		12,127.3	8,050.3	4,077.1		51	%



NGLs	Six Months Ended				Six Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBbl)				(Bbl per day)
Texas
South Texas	341.1	213.6	127.5		1,884.4	1,180.0	704.5		60	%
East Texas	57.9	112.1	(54.2	)	319.7	619.1	(299.3	)	(48	)%
Mid-Continent	88.6	168.7	(80.1	)	489.7	932.3	(442.6	)	(47	)%
Mississippi	—	—	—		—	—	—		—	%
Appalachia	—	—	—		—	—	—		—	%
	487.6	494.4	(6.8	)	2,693.9	2,731.3	(37.5	)	(1	)%



Natural gas	Six Months Ended				Six Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas
South Texas	1,824	1,105	718		10.1	6.1	4.0		65	%
East Texas	2,107	2,331	(224	)	11.6	12.9	(1.2	)	(10	)%
Mid-Continent	1,119	1,531	(412	)	6.2	8.5	(2.3	)	(27	)%
Mississippi	2,089	2,302	(213	)	11.5	12.7	(1.2	)	(9	)%
Appalachia	72	73	—		0.4	0.4	—		(1	)%
	7,211	7,342	(131	)	39.8	40.6	(0.7	)	(2	)%



Combined total	Six Months Ended				Six Months Ended
	June 30,		Favorable		June 30,		Favorable
	2014	2013	(Unfavorable)		2014	2013	(Unfavorable)		% Change
	(MBOE)				(BOE per day)
Texas
South Texas	2,750	1,726	1,024		15,192.1	9,535.5	5,656.6		59	%
East Texas	435	532	(97	)	2,405.6	2,939.5	(533.9	)	(18	)%
Mid-Continent	335	514	(180	)	1,849.8	2,842.0	(992.2	)	(35	)%
Mississippi	352	391	(38	)	1,947.3	2,157.8	(210.5	)	(10	)%
Appalachia	12	12	—		66.5	67.6	(1.1	)	(2	)%
	3,885	3,175	709		21,461.3	17,542.4	3,918.9		22	%

Total production increased during the six months ended June 30, 2014 compared to the corresponding period of 2013 due primarily to production from the properties acquired and developed from the EF Acquisition and the continued expansion of our legacy development program in South Texas. The increase was partially offset by natural production declines in our East Texas, Mid-Continent and Mississippi regions. Approximately 69% of total production during the six months ended June 30, 2014 was attributable to oil and NGLs, which represents an increase of approximately 37% over the prior year period. During

the six months ended June 30, 2014, our Eagle Ford production represented approximately 71% of our total production compared to approximately 54% from this play during the corresponding period of 2013.

Product Revenues and Prices

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



Crude oil	Six Months Ended							Six Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	208,975	$	137,977	$	70,998		$	99.29	$	103.89	$	(4.60	)
East Texas	2,626		3,107		(481		)	99.40		98.44		0.96
Mid-Continent	5,659		8,106		(2,447		)	94.94		89.63		5.31
Mississippi	406		723		(317		)	95.57		106.17		(10.59		)
Appalachia	—		12		(12		)	—		—		NM
	$	217,666	$	149,925	$	67,741		$	99.16	$	102.89	$	(3.73	)



NGLs	Six Months Ended							Six Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	9,642	$	5,215	$	4,427		$	28.27	$	24.42	$	3.85
East Texas	2,916		3,232		(316		)	50.39		28.84		21.55
Mid-Continent	4,852		5,993		(1,141		)	54.74		35.51		19.23
Mississippi	—		—		—			—		—		—
Appalachia	—		—		—			—		—		—
	$	17,410	$	14,440	$	2,970		$	35.71	$	29.21	$	6.50



Natural gas	Six Months Ended							Six Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Mcfe)
Texas
South Texas	$	8,303	$	4,013	$	4,290		$	4.55	$	3.63	$	0.92
East Texas	10,429		7,575		2,854			4.95		3.25		1.70
Mid-Continent	5,482		6,408		(926		)	4.90		4.18		0.71
Mississippi	9,983		8,725		1,258			4.78		3.79		0.99
Appalachia	308		872		(564		)	4.27		NM		NM
	$	34,505	$	27,593	$	6,912		$	4.78	$	3.76	$	1.03



Combined total	Six Months Ended							Six Months Ended
	June 30,				Favorable			June 30,				Favorable
	2014		2013		(Unfavorable)			2014		2013		(Unfavorable)
								($ per Bbl)
Texas
South Texas	$	226,920	$	147,205	$	79,715		$	82.52	$	85.29	$	(2.77	)
East Texas	15,971		13,914		2,057			36.68		26.15		10.53
Mid-Continent	15,993		20,507		(4,514		)	47.77		39.87		7.90
Mississippi	10,389		9,448		941			29.48		24.19		5.29
Appalachia	308		884		(576		)	25.60		NM		NM
	$	269,581	$	191,958	$	77,623		$	69.40	$	60.46	$	8.94

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



	Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	75,930		$	(8,189	)	$	67,741
NGL	(198		)	3,168			2,970
Natural gas	(493		)	7,405			6,912
	$	75,239		$	2,384		$	77,623

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 six months ended June 30, 2014 and 2013, we paid $10.3 million and received $5.8 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:



	Six Months Ended
	June 30,					Favorable
	2014			2013		(Unfavorable)			% Change
Crude oil revenues as reported	$	217,666		$	149,925	$	67,741		45	%
Cash settlements of crude oil derivatives, net	(8,365		)	5,277		(13,642		)	NM
	$	209,301		$	155,202	$	54,099		35	%

Crude oil prices per Bbl, as reported	$	99.16		$	102.89	$	(3.73	)	(4	)%
Cash settlements of crude oil derivatives per Bbl	(3.81		)	3.62		(7.43		)	NM
	$	95.35		$	106.51	$	(11.16	)	(10	)%

Natural gas revenues as reported	$	34,505		$	27,593	$	6,912		25	%
Cash settlements of natural gas derivatives, net	(1,914		)	513		(2,427		)	(473	)%
	$	32,591		$	28,106	$	4,485		16	%

Natural gas prices per Mcf, as reported	$	4.78		$	3.76	$	1.03		27	%
Cash settlements of natural gas derivatives per Mcf	(0.27		)	0.07		(0.34		)	(486	)%
	$	4.51		$	3.83	$	0.69		18	%

Gain (Loss) on Sales of Property and Equipment

In the six months ended June 30, 2014, we recognized a gain of $56.8 million in connection with the sale of our gathering assets in South Texas, including $56.7 million recognized upon the closing of the sale and $0.2 million attributable to the amortization of the deferred portion of the gain. In the six months ended June 30, 2013, we recognized a loss related to certain properties in West Virginia associated with our 2012 sale of Appalachian natural gas assets.

Other Revenues

Other income includes gathering, transportation, compression and water supply and disposal fees, net of marketing and related expenses. The increase during the six months ended June 30, 2014 was attributable to income related to water supply and disposal.

Production and Lifting Costs



	Six Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Lease operating	$	22,807	$	16,434	$	(6,373	)	(39	)%
Per unit of production ($/BOE)	$	5.87	$	5.18	$	(0.69	)	(13	)%

Lease operating expense increased during the six months ended June 30, 2014 due primarily to higher chemical, water disposal and labor costs associated with the expansion of operations in the South Texas region. In addition we incurred higher

compression costs attributable to higher natural gas production in South Texas. As discussed in Key Developments, we sold our natural gas gathering assets in the South Texas region and entered into an agreement with the buyer to provide us natural gas gathering and compression services. We began incurring costs for these services in February 2014. We also incurred higher downhole maintenance costs, particularly in our East Texas region, during the six months ended June 30, 2014.



	Six Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)		% Change
Gathering, processing and transportation	$	6,487	$	6,559	$	72	1	%
Per unit of production ($/BOE)	$	1.67	$	2.07	$	0.40	19	%

Gathering, processing and transportation charges decreased during the six months ended June 30, 2014, due primarily to lower natural gas and NGL production volume in our East Texas, Mid-Continent and Mississippi regions. The decrease was offset partially by gathering charges for natural gas and NGL production in the South Texas region attributable to the new gathering and compression services agreement discussed above.



	Six Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Production and ad valorem taxes
Production/severance taxes	$	11,894		$	8,692		$	(3,202	)	(37	)%
Ad valorem taxes	2,921			4,243			1,322			31	%
	$	14,815		$	12,935		$	(1,880	)	(15	)%
Per unit production ($/BOE)	$	3.81		$	4.07		$	0.20		5	%
Production/severance tax rate as a percent of product revenue	4.4		%	4.5		%

Production taxes increased during the six months ended June 30, 2014 due primarily to the higher level of production in the South Texas region partially offset by severance tax audit refunds for natural gas production in Mississippi.

General and Administrative

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



	Six Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)			% Change
General and administrative expenses	$	21,545	$	19,811	$	(1,734	)	(9	)%
Share-based compensation (liability-classified)	6,992		449		(6,543		)	NM
Share-based compensation (equity-classified)	1,651		3,771		2,120			56	%
EF Acquisition-related transaction costs	—		2,396		2,396			NM
EF Acquisition-related arbitration and other costs	587		—		(587		)	NM
ERP system development costs	744		172		(572		)	NM
Restructuring expenses	9		—		(9		)	NM
	$	31,528	$	26,599	$	(4,929	)	(19	)%
Per unit of production ($/BOE)	$	8.12	$	8.38	0.26			3	%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	5.89	$	7.05	1.16			16	%
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	5.55	$	6.24	0.69			11	%

On a unit of production basis, our general and administrative expenses, excluding liability and equity-classified share-based compensation declined during the six months ended June 30, 2014 compared to the 2013 period reflecting the growth in scale of our operations. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the increase in fair value of the 2012 through 2014 PBRSU grants. The increase in the fair value of the PBRSUs is attributable to our common stock performance relative to a defined peer group. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the six months ended June 30, 2014 due primarily to fewer employees receiving grants. In 2013, we incurred transaction costs associated with the EF Acquisition including advisory, legal, due diligence and other professional fees. In 2014, we incurred costs including legal and litigation support fees attributable to our ongoing arbitration with the seller from the EF Acquisition transaction. In the six months ended June 30, 2014, we also incurred certain costs not eligible for capitalization, including post-implementation support and training with respect to our recently

completed ERP system replacement. Similar charges incurred during the prior year period include preliminary project analysis costs.

Exploration

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



	Six Months Ended
	June 30,				Favorable
	2014		2013		(Unfavorable)			% Change
Unproved leasehold amortization	$	6,579	$	10,408	$	3,829		37	%
Geological and geophysical costs	4,580		2,797		(1,783		)	(64	)%
Other, primarily delay rentals	850		935		85			9	%
	$	12,009	$	14,140	$	2,131		15	%

Unproved leasehold amortization decreased during the six months ended June 30, 2014 due primarily to the classification of our unproved property in the Eagle Ford as a “significant leasehold” effective July 1, 2013. Accordingly, our unproved acreage in this region is no longer subject to systematic amortization. Geological and geophysical costs increased as a result of the acquisition of certain seismic data attributable to our drilling program in South Texas and other regions. Delay rentals decreased as the prior year period included charges attributable to undeveloped acreage acquired in connection with the EF Acquisition.

Depreciation, Depletion and Amortization (DD&A)

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



	Six Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
DD&A expense	$	143,624		$	115,905		$	(27,719	)	(24	)%
DD&A rate ($/BOE)	$	36.97		$	36.51		$	(0.46	)	(1	)%

	Production			Rates			Total
DD&A variance due to:	$	(25,893	)	$	(1,826	)	$	(27,719	)

The effect of higher overall production volumes as well as higher depletion rates associated with oil and NGL production were the primary factors attributable to 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.

Impairments

In June 2014, we entered into a definitive agreement to sell our Selma Chalk assets (primarily natural gas) in Mississippi for gross cash proceeds of $72.7 million. The sale is expected to close in the third quarter of 2014 and we anticipate receiving approximately $71.0 million of proceeds, net of transaction costs and customary closing adjustments. An impairment charge of $117.9 million was recognized in the three months ended June 30, 2014 with respect to these assets.

Interest Expense

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



	Six Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Interest on borrowings and related fees	$	46,918		$	34,485		$	(12,433	)	(36	)%
Accretion of original issue discount	—			431			431			100	%
Amortization of debt issuance costs	2,051			1,454			(597		)	(41	)%
Capitalized interest	(3,206		)	(83		)	3,123			3,763	%
	$	45,763		$	36,287		$	(9,476	)	(26	)%
Weighted-average debt outstanding	$	1,249,615		$	851,483
Weighted average interest rate	7.84		%	8.54		%

Interest expense increased during the six months ended June 30, 2014 due primarily to higher overall weighted-average debt outstanding attributable to the issuance of the 2020 Senior Notes, in April 2013, and higher average outstanding borrowings under the Revolver. The increase in interest expense was partially offset by higher capitalized interest resulting

from the significant increase in the value of our proved undeveloped and unproved properties following the EF Acquisition and the absence of accretion of original issue discount attributable to the 2016 Senior Notes which were retired in connection with the Tender Offer and the Redemption in May 2013. The weighted-average interest rate declined during the six months ended June 30, 2014 due primarily to the replacement of the 2016 Senior Notes with the 2020 Senior Notes as well as borrowings under the Revolver, which carry lower interest rates.

Loss on Extinguishment of Debt

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

Derivatives

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



	Six Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)			% Change
Oil and gas derivatives settled	$	(10,279	)	$	5,790		$	(16,069	)	(278	)%
Oil and gas derivatives loss	(48,048		)	(4,963		)	(43,085		)	(868	)%
	$	(58,327	)	$	827		$	(59,154	)	7,153	%

We paid settlements of $8.4 million for crude oil derivatives and $1.9 million for natural gas derivatives during the six months ended June 30, 2014 and received settlements of $5.3 million from crude oil derivatives and $0.5 million from natural gas derivatives during the six months ended June 30, 2013.

Income Taxes



	Six Months Ended
	June 30,						Favorable
	2014			2013			(Unfavorable)		% Change
Income tax benefit	$	42,452		$	22,471		$	19,981	89	%
Effective tax rate	34.2		%	35.0		%

We recognized income tax expense for the six months ended June 30, 2014 and 2013 at effective tax rates of 34.2% and 35.0%, respectively. The effective tax rate reflects the adverse effect of losses incurred in certain jurisdictions for which we may not realize a tax benefit and have therefore recorded a valuation allowance against the related deferred tax assets. Additionally, our effective tax rate is also adversely impacted by the amount of losses in certain subsidiaries relative to taxable income of the Company.

Financial Condition

Liquidity

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

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

Capital Resources

In 2014, we anticipate making capital expenditures, excluding any acquisitions, of up to approximately $808 million. Based on expenditures to date and forecasted activity for the remainder of 2014, we expect to allocate 98% of our capital expenditures to the Eagle Ford. This allocation includes approximately 82 percent for drilling and completions, 14 percent for leasehold acquisition and four percent for facilities and other projects. The total forecasted activity assumes a drilling program utilizing a seven operated drilling rigs in the Eagle Ford increasing to eight in September 2014. We continually review drilling and other capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, industry conditions, cash from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the Cash Flows discussion that follows.

Cash From Operating Activities. We actively manage the exposure of our revenues to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices, the magnitude of our capital program and our operating strategy. During the six months ended June 30, 2014, our commodity derivatives portfolio resulted in $8.4 million of net cash payments related to higher than anticipated prices received for our crude oil production and $1.9 million of net cash payments attributable to higher than anticipated prices received for our natural gas production.

We have hedged approximately 12,500 barrels of daily crude oil production, or approximately 70 percent of our estimated crude oil production for the remainder of 2014, at a weighted-average floor/swap price of $92.80 per barrel. For 2015 and 2016, we have hedged approximately 11,500 and 3,000 barrels of daily crude oil production at weighted-average floor/swap prices of $90.17 and $90.84 per barrel. In addition, we have hedged 10,000 million British Thermal Units, or MMBtu, of daily natural gas production, or approximately 25 percent of our estimated natural gas production for the remainder of 2014 at a weighted-average floor/swap price of $4.20 per MMBtu. For the first quarter of 2015, we have hedged 5,000 MMBtu of daily natural gas production at a weighted-average floor/swap price of $4.50 per MMBtu.

Revolver Borrowings. The Revolver provides for a $450 million revolving commitment. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $150 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. Upon the expected closing of the sale of our Selma Chalk assets in the third quarter of 2014, the borrowing base will be reduced by $37.5 million from $475 million to $437.5 million. The next semi-annual redetermination is scheduled for November 2014. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $1.7 million outstanding as of June 30, 2014. As of June 30, 2014, our available borrowing capacity under the Revolver was $393.3 million.

For additional information regarding the terms and covenants associated with the Revolver, see the Capitalization discussion that follows.

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



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended June 30, 2014	$	273,747	$	407,000	2.4446	%
Six months ended June 30, 2014	$	236,044	$	407,000	2.2836	%

Proceeds from Sales of Assets. In July 2014, we received approximately $147 million, net of transactions costs, from the sale of rights to construct an oil gathering system in South Texas. In the third quarter of 2014, we expect to receive approximately $71 million of net proceeds from the sale of our Selma Chalk assets in Mississippi. In January 2014, we sold our natural gas gathering and gas lift assets in South Texas for proceeds of approximately $96 million, net of closing costs and adjustments. Furthermore, we continually evaluate potential sales of non-core assets, including certain natural gas properties and non-strategic undeveloped acreage, among others.

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

Cash Flows

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



	Six Months Ended
	June 30,
	2014			2013			Variance
Cash flows from operating activities
Operating cash flows, net	$	195,262		$	134,208		$	61,054
Working capital changes, net	(39,507		)	16,895			(56,402		)
Commodity derivative settlements (paid) received, net:							—
Crude oil	(8,365		)	5,277			(13,642		)
Natural gas	(1,914		)	513			(2,427		)
Interest payments, net of amounts capitalized	(43,828		)	(23,132		)	(20,696		)
Acquisition arbitration, transaction and other costs paid	(744		)	(2,396		)	1,652
ERP system development costs paid	(587		)	(172		)	(415		)
Restructuring and exit costs paid	(1,124		)	(1,442		)	318
Net cash provided by operating activities	99,193			129,751			(30,558		)
Cash flows from investing activities
Acquisition and working capital-related settlements, net	—			(394,549		)	394,549
Capital expenditures - property and equipment	(350,580		)	(229,319		)	(121,261		)
Proceeds from sales of assets, net	96,632			867			95,765
Net cash used in investing activities	(253,948		)	(623,001		)	(25,496		)
Cash flows from financing activities
Proceeds from the issuance of preferred stock, net	313,646			—			313,646
Payments made to induce conversion of preferred stock	(3,368		)	—			(3,368		)
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	(151,000		)	67,000			(218,000		)
Debt issuance costs paid	(151		)	(24,698		)	24,547
Dividends paid on preferred and common stock	(3,836		)	(3,412		)	(424		)
Other, net	1,085			(110		)	1,195
Net cash provided by financing activities	156,376			494,690			(338,314		)
Net increase in cash and cash equivalents	$	1,621		$	1,440		$	(394,368	)

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

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

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

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



	Six Months Ended
	June 30,
	2014		2013
Oil and gas:
Drilling and completion	$	289,500	$	202,883
Lease acquisitions and other land-related costs¹	49,667		25,006
Geological and geophysical (seismic) costs	4,580		2,797
Pipeline, gathering facilities and other equipment	7,187		9,774
	350,934		240,460
Other - Corporate	972		1,382
Total capital program costs	$	351,906	$	241,842

______________________

¹ Includes site preparation and other pre-drilling costs.

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:



	Six Months Ended
	June 30,
	2014			2013
Total capital program costs	$	351,906		$	241,842
Decrease (increase) in accrued capitalized costs	858			(7,734		)
Less:
Exploration costs charged to operations:
Geological and geophysical (seismic)	(4,580		)	(2,797		)
Other, primarily delay rentals	(780		)	(935		)
Transfers from tubular inventory and well materials	(409		)	(1,155		)
Add:
Tubular inventory and well materials purchased in advance of drilling	379			15
Capitalized interest	3,206			83
Total cash paid for capital expenditures	$	350,580		$	229,319

Cash Flows From Financing Activities. In June 2014, we issued the Series B Preferred Stock for net proceeds of approximately $314 million. Cash flows from financing activities for the six months ended June 30, 2014 included net repayments under the Revolver, funded primarily with proceeds from the Series B Preferred Stock and sale of our natural gas gathering assets in South Texas while the 2013 period includes net borrowings under the Revolver which were used to finance a portion of our capital program. In June 2014, we paid $3.4 million to induce the conversion of approximately 23 percent of the outstanding shares of the Series A Preferred Stock. Both periods included dividends paid on the Series A Preferred Stock. In April 2013, we issued the 2020 Senior Notes which were used to fund the EF Acquisition and a portion of the Tender Offer and the Redemption of our 2016 Senior Notes. We incurred and paid costs in the 2014 and 2013 periods associated with amendments to our Revolver in connection with the Series B Preferred Stock and the 2020 Senior Notes transactions as well as costs paid in the 2013 period associated with the issuance of the 2020 Senior Notes. We also received proceeds of $1.1 million during the 2014 period from the exercise of stock options.

Capitalization

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



	June 30,			December 31,
	2014			2013
Revolving credit facility	$	55,000		$	206,000
Senior notes due 2019	300,000			300,000
Senior notes due 2020	775,000			775,000
Total debt	1,130,000			1,281,000
Shareholders equity ¹	1,016,392			788,804
	$	2,146,392		$	2,069,804
Debt as a % of total capitalization	53		%	62		%

_____________________

¹ Includes 8,880 and 11,500 shares of the Series A Preferred Stock as of June 30, 2014 and December 31, 2013, respectively, and 32,500 shares of the Series B Preferred Stock as of June 30, 2014. Both series of preferred stock have a liquidation preference of $10,000 per share representing a total of $414 million and $115 million as of June 30, 2014 and December 31, 2013, respectively.

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, 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 June 30, 2014, the actual interest rate applicable to the Revolver was 1.6875% which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.50%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2014, commitment fees were being charged at a rate of 0.375%.

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

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

2020 Senior Notes. The 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.5% payable on May 1 and November 1 of each year. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

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

Each share of the Series A Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $6.00 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the Series A Preferred Stock. The initial conversion price represents a premium of 20 percent relative to the

2012 common stock offering price of $5.00 per share. The Series A Preferred Stock is not redeemable for cash by us or the holders at any time. At any time on or after October 15, 2017, we may, at our option, cause all outstanding shares of the Series A Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the Series A Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value. During the six months ended June 30, 2014, a total of 2,620 shares, or 262,012 depositary shares, of the Series A Preferred Stock were converted into 4.4 million shares of common stock.

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

Each share of the Series B Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion price, which is initially $18.34 per share and is subject to specified anti-dilution adjustments. The initial conversion rate is equal to 545.17 shares of our common stock for each share of the Series B Preferred Stock. The initial conversion price represents a premium of 30 percent relative to the last reported sales price of $14.11 per common share prior to the offering of the Series B Preferred Stock. The Series B Preferred Stock is not redeemable for cash by us or the holders at any time. At any time on or after July 15, 2019, we may, at our option, cause all outstanding shares of the Series B Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion price if the closing sale price of our common stock exceeds 130% of the then-applicable conversion price for a specified period prior to conversion. If a holder elects to convert shares of the Series B Preferred Stock upon the occurrence of certain specified fundamental changes, we may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.

Covenant Compliance. The Revolver and the indentures associated with our senior notes require us to maintain certain financial and non-financial covenants. These covenants impose limitations on our ability to pay dividends as well as our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries, among other requirements. As of June 30, 2014 and through the date upon which our Condensed Consolidated Financial Statements were issued, we were in compliance with these covenants.

In the event that we would be in default of a covenant under the Revolver, we could request a waiver of the covenant from our bank group. Should the banks deny our request to waive the covenant requirement, the outstanding borrowings under the Revolver would become payable on demand and would be reclassified as a component of current liabilities on our Condensed Consolidated Balance Sheets.

The 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.

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

As of June 30, 2014 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants. The following table summarizes the actual results of our financial covenant compliance under the Revolver as of and for the period ended June 30, 2014:



	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.50 to 1	3.1 to 1
Current ratio	> 1.00 to 1	3.0 to 1
Interest coverage	> 2.25 to 1	3.6 to 1

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2013.

New Accounting Standards

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

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk.

Interest Rate Risk

Our interest rate risk is attributable to our borrowings under the Revolver, which is our only long-term debt instrument with variable interest rates. As of June 30, 2014, we had borrowings of $55 million under the Revolver at an interest rate of 1.6875%. Assuming a constant borrowing level of $55 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 $0.6 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 June 30, 2014, our commodity derivative portfolio was in a net liability position. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with five of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions.

During the six months ended June 30, 2014, we reported net commodity derivative losses of $58.3 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 June 30, 2014:



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Third quarter 2014	Collars	2,000	$	90.00	$	94.33	$	—	$	1,862
Fourth quarter 2014	Collars	2,000	$	90.00	$	94.33	—		1,487
First quarter 2015	Collars	4,000	$	87.50	$	94.66	—		2,284
Second quarter 2015	Collars	4,000	$	87.50	$	94.66	—		1,741
Third quarter 2015	Collars	3,000	$	86.67	$	94.73	—		1,002
Fourth quarter 2015	Collars	3,000	$	86.67	$	94.73	—		719
Third quarter 2014	Swaps	10,000	$	93.21			—		10,250
Fourth quarter 2014	Swaps	11,000	$	93.45			—		8,489
First quarter 2015	Swaps	9,000	$	91.81			—		6,227
Second quarter 2015	Swaps	9,000	$	91.81			—		4,637
Third quarter 2015	Swaps	8,000	$	91.06			—		3,478
Fourth quarter 2015	Swaps	8,000	$	91.06			—		2,615
First quarter 2016	Swaps	2,000	$	90.43			—		418
First quarter 2016	Swaps	2,000	$	90.43			—		218
First quarter 2016	Swaps	2,000	$	90.43			—		75
First quarter 2016	Swaps	2,000	$	90.43			17		—
First quarter 2015	Swaptions	1,000	$	88.00			—		896
Second quarter 2015	Swaptions	1,000	$	88.00			—		896
Third quarter 2015	Swaptions	1,000	$	88.00			—		896
Fourth quarter 2015	Swaptions	1,000	$	88.00			—		895

Natural Gas:		(in MMBtu)	($/MMBtu)
Third quarter 2014	Swaps	15,000	$	4.10			—		455
Fourth quarter 2014	Swaps	5,000	$	4.50			10		—
First quarter 2015	Swaps	5,000	$	4.50			—		16
Settlements to be paid in subsequent period							—		3,277

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	$	(75.1	)	$	72.2
Effect on the fair value of natural gas derivatives	$	(1.8	)	$	1.8

Effect on the remainder of 2014 operating income, excluding crude oil derivatives	$	39.1		$	(39.1	)
Effect on the remainder of 2014 operating income, excluding natural gas derivatives	$	7.9		$	(7.9	)

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 June 30, 2014. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 2014, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

Part II. OTHER INFORMATION


Item 1	Legal Proceedings

Commencing December 2013, we were involved in an arbitration with MHR, the seller in our EF Acquisition. The arbitration related to disputes we had with MHR regarding contractual adjustments to the purchase price for the EF Acquisition and suspense funds that we believed MHR was obligated to transfer to us. Effective with the one-year anniversary of the acquisition date, we recorded a receivable for final purchase price adjustments representing management’s estimate of the outcome of the arbitration. On July 29, 2014, we received the arbitrator’s determination, which indicates that MHR is required to pay us approximately $31.0 million of purchase price adjustments and to transfer to us approximately $2.7 million of revenue suspense funds due to partners and royalty owners. The award is consistent with the estimate made by management. We are also entitled to interest on the funds since the Acquisition Date.


Item 6	Exhibits



(2.1)	Purchase and Sale Agreement, dated May 30, 2014, by and between Penn Virginia Oil & Gas Corporation and KKR Management Holding L.P. (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on June 2, 2014).

(3.1)	Articles of Amendment of the Restated Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2014).

(3.2)	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed on June 16, 2014).

(4.1)	Deposit Agreement, dated June 16, 2014, among Penn Virginia Corporation, American Stock Transfer & Trust Company, LLC and the holders from time to time of the depositary receipts described therein (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2014).

(4.2)	Form of depositary receipt (incorporated by reference to Exhibit A to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2014).

(10.1)	Fifth Amendment and Borrowing Base Redetermination Agreement, dated as of May 12, 2014, among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on May 15, 2014)

(10.1.1)	Sixth Amendment to Credit Agreement dated as of June 16, 2014, among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on June 16, 2014)

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

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

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

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

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

(101.INS)	XBRL Instance Document

(101.SCH)	XBRL Taxonomy Extension Schema Document

(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document

(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document

(101.LAB)	XBRL Taxonomy Extension Label Linkbase Document

(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document

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

July 30, 2014	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)