PVA-2015.06.30-10Q



Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2015 and 2014	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended June 30, 2015 and 2014	4
	Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2015 and 2014	6
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	7
	2. Basis of Presentation	7
	3. Divestitures	7
	4. Accounts Receivable and Major Customers	8
	5. Derivative Instruments	8
	6. Property and Equipment	10
	7. Long-Term Debt	10
	8. Income Taxes	11
	9. Firm Transportation Obligation	11
	10. Additional Balance Sheet Detail	12
	11. Fair Value Measurements	13
	12. Commitments and Contingencies	14
	13. Shareholders' Equity	15
	14. Share-Based Compensation	16
	15. Interest Expense	16
	16. Earnings per Share	17
Forward-Looking Statements		18
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:
	Overview and Executive Summary	19
	Key Developments	20
	Results of Operations	22
	Financial Condition	29
	Critical Accounting Estimates	35
3.	Quantitative and Qualitative Disclosures About Market Risk	35
4.	Controls and Procedures	36
Part II - Other Information
1.	Legal Proceedings	37
6.	Exhibits	37
Signatures		38



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Revenues
Crude oil	$	70,672		$	112,090		$	129,840		$	217,666
Natural gas liquids (NGLs)	5,191			8,037			10,587			17,410
Natural gas	7,260			16,302			15,831			34,505
Gain (loss) on sales of property and equipment, net	66			(51		)	(25		)	56,775
Other, net	427			2,983			1,910			2,870
Total revenues	83,616			139,361			158,143			329,226
Operating expenses
Lease operating	10,907			12,001			22,476			22,117
Gathering, processing and transportation	6,383			3,928			13,881			7,177
Production and ad valorem taxes	4,967			7,510			9,656			14,815
General and administrative	11,479			14,840			23,449			31,528
Exploration	4,362			3,373			10,249			12,009
Depreciation, depletion and amortization	85,416			71,437			176,206			143,624
Impairments	1,084			117,908			1,084			117,908
Total operating expenses	124,598			230,997			257,001			349,178
Operating loss	(40,982		)	(91,636		)	(98,858		)	(19,952		)
Other income (expense)
Interest expense	(23,023		)	(23,229		)	(45,036		)	(45,763		)
Derivatives	(15,495		)	(42,665		)	7,372			(58,327		)
Other	(540		)	30			(542		)	31
Loss before income taxes	(80,040		)	(157,500		)	(137,064		)	(124,011		)
Income tax (expense) benefit	(89		)	56,716			(230		)	42,452
Net loss	(80,129		)	(100,784		)	(137,294		)	(81,559		)
Preferred stock dividends	(6,067		)	(1,718		)	(12,134		)	(3,440		)
Induced conversion of preferred stock	—			(3,368		)	—			(3,368		)
Net loss attributable to common shareholders	$	(86,196	)	$	(105,870	)	$	(149,428	)	$	(88,367	)
Net loss per share:
Basic	$	(1.19	)	$	(1.59	)	$	(2.07	)	$	(1.34	)
Diluted	$	(1.19	)	$	(1.59	)	$	(2.07	)	$	(1.34	)

Weighted average shares outstanding – basic	72,398			66,514			72,330			66,065
Weighted average shares outstanding – diluted	72,398			66,514			72,330			66,065



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net loss	$	(80,129	)	$	(100,784	)	$	(137,294	)	$	(81,559	)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax of $(5) and $(11) in 2015 and $13 and $26 in 2014	(10		)	24			(21		)	49
	(10		)	24			(21		)	49
Comprehensive loss	$	(80,139	)	$	(100,760	)	$	(137,315	)	$	(81,510	)



	As of
	June 30,			December 31,
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	4,441		$	6,252
Accounts receivable, net of allowance for doubtful accounts	104,636			189,627
Derivative assets	80,372			128,981
Deferred income taxes	—			53
Other current assets	8,381			10,114
Total current assets	197,830			335,027
Property and equipment, net (successful efforts method)	1,888,892			1,825,098
Derivative assets	19,546			35,897
Other assets	6,322			5,841
Total assets	$	2,112,590		$	2,201,863

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	197,889		$	312,227
Derivative liabilities	—			—
Total current liabilities	197,889			312,227
Other liabilities	117,582			123,886
Deferred income taxes	4,838			4,504
Long-term debt, net of unamortized issuance costs	1,264,363			1,085,429

Commitments and contingencies (Note 12)

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; Series A – 7,945 shares issued as of June 30, 2015 and December 31, 2014 and Series B – 32,500 shares issued as of June 30, 2015 and December 31, 2014, each with a redemption value of $10,000 per share	4,044			4,044
Common stock of $0.01 par value – 228,000,000 shares authorized; 71,676,606 and 71,568,936 shares issued as of June 30, 2015 and December 31, 2014, respectively	530			529
Paid-in capital	1,207,854			1,206,305
Accumulated deficit	(684,604		)	(535,176		)
Deferred compensation obligation	3,354			3,211
Accumulated other comprehensive income	228			249
Treasury stock – 293,426 and 262,070 shares of common stock, at cost, as of June 30, 2015 and December 31, 2014, respectively	(3,488		)	(3,345		)
Total shareholders’ equity	527,918			675,817
Total liabilities and shareholders’ equity	$	2,112,590		$	2,201,863



	Six Months Ended
	June 30,
	2015			2014
Cash flows from operating activities
Net loss	$	(137,294	)	$	(81,559	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	176,206			143,624
Impairments	1,084			117,908
Accretion of firm transportation obligation	445			584
Derivative contracts:
Net (gains) losses	(7,372		)	58,327
Cash settlements, net	72,332			(10,279		)
Deferred income tax expense (benefit)	230			(42,452		)
Loss (gain) on sales of assets, net	25			(56,775		)
Non-cash exploration expense	4,005			6,579
Non-cash interest expense	2,280			2,051
Share-based compensation (equity-classified)	2,106			1,651
Other, net	3			281
Changes in operating assets and liabilities, net	(15,769		)	(40,747		)
Net cash provided by operating activities	98,281			99,193

Cash flows from investing activities
Capital expenditures – property and equipment	(263,993		)	(350,580		)
Proceeds from sales of assets, net	(221		)	96,632
Net cash used in investing activities	(264,214		)	(253,948		)

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 revolving credit facility borrowings	197,000			302,000
Repayment of revolving credit facility borrowings	(20,000		)	(453,000		)
Debt issuance costs paid	(744		)	(151		)
Dividends paid on preferred stock	(12,134		)	(3,836		)
Other, net	—			1,085
Net cash provided by financing activities	164,122			156,376
Net (decrease) increase in cash and cash equivalents	(1,811		)	1,621
Cash and cash equivalents – beginning of period	6,252			23,474
Cash and cash equivalents – end of period	$	4,441		$	25,095

Supplemental disclosures:
Cash paid for:
Interest	$	46,041		$	47,034
Income taxes	$	7		$	100
Non-cash investing activities:
Changes in accrued liabilities related to capital expenditures	$	(20,570	)	$	(858	)

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

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2014. Operating results for the six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015. Certain amounts for the 2014 period have been reclassified to conform to the current year presentation.

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs (“ASU 2015–03”) on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented. Issuance costs associated with our revolving credit facility (the “Revolver”) continue to be presented, net of amortization, as a component of Other assets (see Note 10).

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, currently anticipated on January 1, 2018. The standard permits the use of either the retrospective or cumulative effect transition method upon adoption. We are evaluating the effect that ASU 2014–09 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of ASU 2014–09 on our ongoing financial reporting.

Management has evaluated all activities of the Company through the date upon which our Condensed Consolidated Financial Statements were issued and concluded that, except for the pending sale of our East Texas assets (see Note 3), no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to Condensed Consolidated Financial Statements.

In January 2014, we sold our natural gas gathering and gas lift assets in South Texas to American Midstream Partners, LP (“AMID”) for proceeds of approximately $96 million, net of transaction costs. Concurrent with the sale, we entered into a long-term agreement with AMID to provide us natural gas gathering, compression and gas lift services for a substantial portion of our current and future South Texas natural gas production. We realized a gain of $67.3 million, of which $56.7 million was recognized upon the closing of the transaction and the remaining $10.6 million was deferred and is being recognized over a twenty-five year period. We amortized $0.2 million of the deferred gain during each of the six months ended June 30, 2015 and 2014, respectively. As of June 30, 2015, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $9.6 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

In July 2014, we sold the rights to construct a crude oil gathering and intermediate transportation system in South Texas to Republic Midstream, LLC (“Republic”) for proceeds of approximately $147 million, net of transaction costs. Concurrent with the sale, we entered into long-term agreements with Republic to provide us gathering and intermediate transportation services for a substantial portion of our future South Texas crude oil and condensate production. We realized a gain of $147.1 million, of which $63.0 million was recognized upon the closing of the transaction and the remaining $84.1 million was deferred and will be recognized over a twenty-five year period beginning after the system has been constructed and is operational, currently expected to be in the fourth quarter of 2015. As of June 30, 2015, $2.6 million of the deferred gain is included as a component of Accounts payable and accrued expenses and $81.5 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

For the six months ended June 30, 2015, three customers accounted for $96.7 million, or approximately 62%, of our consolidated product revenues. The revenues generated from these customers during the six months ended June 30, 2015 were $41.2 million, $36.1 million and $19.4 million, or 26%, 23% and 13% of the consolidated total, respectively. As of June 30, 2015, $30.2 million, or approximately 50% of our consolidated accounts receivable from customers was related to these customers. 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 approximately 18%, 13%, 13% and 11% of the consolidated total, respectively. As of December 31, 2014, $36.1 million, or approximately 58% 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.

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

The counterparty to a collar or swap contract is required to make a payment to us if the settlement price for any settlement period is below the floor or swap price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling or swap price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

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



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Third quarter 2015 ¹	Collars	3,000	$	86.67	$	94.73	$	5,484	$	—
Fourth quarter 2015 ¹	Collars	3,000	$	86.67	$	94.73	5,186		—
Third quarter 2015 ¹	Swaps	8,000	$	91.06			20,056		—
Fourth quarter 2015 ¹	Swaps	8,000	$	91.06			19,238		—
First quarter 2016	Swaps	6,000	$	80.41			10,273		—
Second quarter 2016	Swaps	6,000	$	80.41			10,011		—
Third quarter 2016	Swaps	6,000	$	80.41			9,911		—
Fourth quarter 2016	Swaps	6,000	$	80.41			9,635		—
Settlements to be received in subsequent period							10,125		—

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



		Fair Values as of
		June 30, 2015				December 31, 2014
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	80,372	$	—	$	128,981	$	—
Commodity contracts	Derivative assets/liabilities – noncurrent	19,546		—		35,897		—
		$	99,918	$	—	$	164,878	$	—

As of June 30, 2015, we reported a commodity derivative asset of $99.9 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with four of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.



	As of
	June 30, 2015				December 31, 2014
	Principal		Unamortized Issuance Costs		Principal		Unamortized Issuance Costs
Revolving credit facility ¹	$	212,000			$	35,000
Senior notes due 2019	300,000		$	3,721	300,000		$	4,131
Senior notes due 2020	775,000		18,916		775,000		20,440
Totals	1,287,000		$	22,637	1,110,000		$	24,571
Long-term debt, net of unamortized issuance costs	$	1,264,363			$	1,085,429

The Revolver provides for a revolving commitment and borrowing base of $425 million. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $175 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The next semi-annual redetermination is scheduled for November 2015 although we expect the borrowing base to be reduced by approximately $30 million prior to the redetermination upon the closing of the sale of our East Texas assets. The Revolver allows for the administrative agent to replace any lender who fails to approve a borrowing base increase approved by lenders representing two-thirds of the aggregate commitment. The Revolver 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 $1.8 million outstanding as of June 30, 2015. As of June 30, 2015, our available borrowing capacity under the Revolver was $211.2 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (“Adjusted LIBOR”), plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, plus, in each case, an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of June 30, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 2.1875%, which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 2.00%. 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, 2015, commitment fees were being charged at a rate of 0.500%.

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

Our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% and are payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to 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.

Our 8.50% 2020 Senior Notes due 2020 (the “2020 Senior Notes”), which were issued at par in April 2013, bear interest at an annual rate of 8.50% and are payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

The guarantees under the Revolver and the 2019 Senior Notes and 2020 Senior Notes are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company and its non-guarantor subsidiaries have no material independent assets or operations. There are no significant restrictions on the ability of the parent company to obtain funds from the Guarantor Subsidiaries through dividends, advances or loans.

Due to the pre-tax operating loss incurred, we recognized a federal income tax benefit for the three and six months ended June 30, 2015 at the statutory rate of 35%; however, the federal tax benefit was fully offset by a valuation allowance against our net deferred tax assets. We considered both the positive and negative evidence in determining that it was more likely than not that some portion or all of our deferred tax assets will not be realized, primarily as a result of recent cumulative losses. The income tax provision also includes a minimal deferred state income tax expense resulting in a combined effective tax rate of 0.2% for the six months ended June 30, 2015. The significant difference between our combined federal and state statutory rate of 35.7% and our estimated effective tax of 0.2% is due primarily to the valuation allowance placed against our deferred tax assets.

We have a contractual obligation for certain firm transportation capacity in the Appalachian region that expires in 2022 and, as a result of the sale of our natural gas assets in West Virginia, Kentucky and Virginia in 2012, we no longer have production to satisfy this commitment. We recognized an obligation in 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

The accretion of the obligation, net of any recoveries from periodic sales of our contractual capacity, is charged as an offset to Other revenue. As of June 30, 2015, $2.8 million of the obligation is classified as current and is included in the Accounts payable and accrued liabilities caption while the remaining $11.4 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.



	As of
	June 30,		December 31,
	2015		2014
Other current assets:
Tubular inventory and well materials ¹	$	4,452	$	5,802
Prepaid expenses	3,825		4,215
Other	104		97
	$	8,381	$	10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	$	4,206	$	4,123
Deferred issuance costs of the Revolver	2,021		1,623
Other	95		95
	$	6,322	$	5,841
Accounts payable and accrued liabilities:
Trade accounts payable	$	84,584	$	174,496
Drilling and other lease operating costs	47,872		68,842
Royalties	26,263		27,883
Compensation – related	12,846		9,197
Interest	15,646		15,555
Preferred stock dividends	6,067		6,067
Other	4,611		10,187
	$	197,889	$	312,227
Other liabilities:
Deferred gains on sales of assets	$	91,226	$	90,569
Firm transportation obligation	11,390		12,042
Asset retirement obligations (“AROs”)	6,191		5,889
Defined benefit pension obligations	1,537		1,753
Postretirement health care benefit obligations	942		890
Compensation – related	1,124		7,631
Deferred compensation – SERP obligations and other	4,243		4,183
Other	929		929
	$	117,582	$	123,886



	As of June 30, 2015
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	80,372		$	—		$	80,372	$	—
Commodity derivative assets – noncurrent	19,546			—			19,546		—
Assets of SERP	4,206			4,206			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,242		)	(4,242		)	—		—



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

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the six months ended June 30, 2015 and 2014.

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

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

As of June 30, 2015, we had contractual commitments for two drilling rigs with terms expiring in September 2015 and February 2016, respectively. The minimum commitment under these agreements is $7.0 million for the second half of 2015 and $1.1 million in 2016. In addition, we have a commitment to purchase certain coil tubing services that expires in December 2015. The minimum commitment for the remaining two quarters of 2015 under this agreement is $7.4 million. The drilling rig and coil tubing services agreements include early termination provisions that would require us to pay penalties if we terminate the agreements prior to the end of their scheduled terms. The amount of penalty is based on the number of days remaining in the contractual term. As of June 30, 2015, the penalty amount would have been $13.3 million had we terminated those agreements on that date.

We have entered into contracts for firm transportation capacity rights for specified volumes per day on various pipeline systems with remaining terms that range from less than one to 13 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. The minimum commitment under these agreements is $1.0 million for the second half of 2015 and approximately $1.1 million per year through 2028. We may sell excess capacity to third parties at our discretion.

We have entered into a long-term agreement for natural gas gathering, compression and gas lift services for a substantial portion of our natural gas production in the South Texas region through 2038. The agreement requires us to make certain minimum fee payments regardless of the volume of natural gas production for the first three years of the term. The minimum fee requirement under this agreement is $2.1 million for the second half of 2015 and $5.0 million in 2016.

We have also entered into long-term agreements for gathering and intermediate pipeline transportation services for a substantial portion of our crude oil and condensate production in the South Texas region. Our payment obligations with respect to these services will begin when construction of the gathering and transportation system is completed, which is expected to be in the fourth quarter of 2015. The agreements also require us to commit certain minimum volumes of crude oil production for the first ten years of the agreements’ terms, which will result in minimum fee requirements of approximately $13.7 million on an annual basis.

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter that remained outstanding as of June 30, 2015. In March 2015, we established an additional $0.3 million reserve for litigation attributable to certain properties that we previously sold. This matter was settled in May 2015 with a cash payment of the amount reserved. As of June 30, 2015, we also had AROs of approximately $6.2 million attributable to the plugging of abandoned wells.



	As of						Preferred								As of
	December 31,						Stock		Dividends			All Other			June 30,
	2014			Net Loss			Offering		Declared ¹			Changes ²			2015
Preferred stock	$	4,044		$	—		$	—	$	—		$	—		$	4,044
Common stock	529			—			—		—			1			530
Paid-in capital	1,206,305			—			—		—			1,549			1,207,854
Accumulated deficit	(535,176		)	(137,294		)	—		(12,134		)	—			(684,604		)
Deferred compensation obligation	3,211			—			—		—			143			3,354
Accumulated other comprehensive income ³	249			—			—		—			(21		)	228
Treasury stock	(3,345		)	—			—		—			(143		)	(3,488		)
	$	675,817		$	(137,294	)	$	—	$	(12,134	)	$	1,529		$	527,918

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

¹ Includes dividends of $300.00 per share on 7,945 and 11,480 shares of our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) during the six months ended June 30, 2015 and 2014, respectively, and $300.00 per share on 32,500 shares of our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”) for the six months ended June 30, 2015.

³ The Accumulated other comprehensive income (“AOCI”) is entirely attributable to our defined benefit pension and postretirement health care plans. The changes in the balance of AOCI for the six months ended June 30, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(32) and $75 and are presented above net of taxes of $(11) and $26.

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

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net loss	$	(80,129	)	$	(100,784	)	$	(137,294	)	$	(81,559	)
Less: Preferred stock dividends ¹	(6,067		)	(1,718		)	(12,134		)	(3,440		)
Less: Induced conversion of preferred stock	—			(3,368		)	—			(3,368		)
Net loss attributable to common shareholders – basic and diluted	$	(86,196	)	$	(105,870	)	$	(149,428	)	$	(88,367	)

Weighted-average shares – basic	72,398			66,514			72,330			66,065
Effect of dilutive securities ²	—			—			—			—
Weighted-average shares – diluted	72,398			66,514			72,330			66,065

² For the three and six months ended June 30, 2015, approximately 31.3 million and 31.5 million, respectively, of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share. For the three and six months ended June 30, 2014, approximately 18.8 million and 17.2 million, respectively, of potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

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:

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. All subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required by applicable law.

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated. Certain year-over-year changes are presented as not meaningful, or “NM,” where disclosure of the actual value does not otherwise enhance the analysis, and certain amounts for the 2014 periods have been reclassified to conform to the current year presentation. Also, due to the combination of different units of volumetric measure, the number of decimal places presented and rounding, certain results may not calculate explicitly from the values presented in the tables.

We are an independent oil and gas company engaged in the onshore exploration, development and production of oil, NGLs and natural gas. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in Oklahoma, primarily the Granite Wash, and the Haynesville Shale and Cotton Valley in East Texas, which we have committed to sell as discussed in Key Developments below. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 million barrels of oil equivalent, or MMBOE, including approximately 14 MMBOE of proved reserves attributable to our East Texas operations.



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Total production (MBOE)	2,140			1,983			4,365			3,885
Average daily production (BOEPD)	23,519			21,786			24,117			21,461
Crude oil and NGL production (MBbl)	1,664			1,380			3,397			2,683
Crude oil and NGL production as a percent of total	78		%	70		%	78		%	69		%
Product revenues, as reported	$	83,123		$	136,429		$	156,258		$	269,581
Product revenues, as adjusted for derivatives	$	117,963		$	129,207		$	228,590		$	259,302
Crude oil and NGL revenues as a percent of total, as reported	91		%	88		%	90		%	87		%
Realized prices:
Crude oil ($/Bbl)	$	55.22		$	100.16		$	49.62		$	99.16
NGL ($/Bbl)	$	13.53		$	30.85		$	13.56		$	35.71
Natural gas ($/Mcf)	$	2.54		$	4.51		$	2.73		$	4.78
Aggregate ($/BOE)	$	38.84		$	68.81		$	35.80		$	69.40
Operating costs ($/BOE):
Lease operating	$	5.10		$	6.05		$	5.15		$	5.69
Gathering, processing and transportation	2.98			1.98			3.18			1.85
Production and ad valorem taxes ($/BOE)	2.32			3.79			2.21			3.81
General and administrative ($/BOE) ¹	4.94			6.54			4.85			5.89
Total operating costs ($/BOE)	$	15.34		$	18.36		$	15.39		$	17.24
Depreciation, depletion and amortization ($/BOE)	$	39.91		$	36.03		$	40.37		$	36.97
Cash provided by operating activities	$	52,729		$	32,633		$	98,281		$	99,193
Cash paid for capital expenditures	$	94,999		$	190,776		$	263,993		$	350,580
Cash and cash equivalents at end of period							$	4,441		$	25,095
Debt outstanding at end of period							$	1,287,000		$	1,130,000
Credit available under revolving credit facility at end of period ²							$	211,196		$	393,346
Net development wells drilled and completed	13.5			15.0			27.6			28.8

_______________________

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.52 and $0.42 for the three months ended June 30, 2015 and 2014 and $0.48 and $0.42 for the six months ended June 30, 2015 and 2014 and liability-classified share-based compensation of $(0.10) and $0.53 for the three months ended June 30, 2015 and 2014 and $0.04 and $1.80 for the six months ended June 30, 2015 and 2014.

In the three months ended June 30, 2015, our crude oil and NGL production increased to 78 percent from 70 percent of our total production compared to the three month period ended June 30, 2014. Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. As of July 24, 2015, we operated 281 producing Eagle Ford wells and had working interests in an additional 36 non-operated producing wells. Through this date, we have accumulated approximately 103,000 net acres in the Eagle Ford. We are currently operating two drilling rigs in the Eagle Ford. Our capital program, which is exclusively dedicated to this play, is being financed with a combination of cash from operating activities, proceeds from the sale of non-core assets and borrowings under the Revolver.

To mitigate the volatile effect of commodity price fluctuations, we have a comprehensive hedging program in place. The Financial Condition discussion that follows and Note 5 to the Condensed Consolidated Financial Statements provides a detailed summary of our open commodity derivative positions as well as the historical results of our hedging program for the three and six months ended June 30, 2015 and 2014.

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) depressed commodity prices and our hedging program, (ii) production, development and capital expenditures in the Eagle Ford, (iii) the sale of our East Texas assets and (iv) an amendment to the Revolver decreasing the commitment and borrowing base and modifying our financial covenants, among other things.

Commodity prices continued to be volatile and depressed during the first half of 2015. Our crude oil derivatives supported our liquidity by providing cash settlements of $34.8 million and $71.7 million during the quarter and six months ended June 30, 2015. We have hedged approximately 11,000 barrels of oil per day, or BOPD, or approximately 80 to 90 percent of our expected crude oil production during the second half of 2015, at a weighted-average floor/swap price of $89.86 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI Crude Oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the second half of 2015. No volumes are subject to the put options in 2016. Our natural gas hedges provided cash settlements of $0.7 million during the first quarter of 2015 and expired at the end of that period. We expect to remain unhedged with respect to natural gas production for the foreseeable future.

Our Eagle Ford production was 20,259 BOEPD during the three months ended June 30, 2015 with oil comprising 13,750 BOPD, or 68 percent, and NGLs and natural gas comprising approximately 17 percent and 15 percent, respectively. Our second quarter production represents a five percent decrease compared to 21,390 BOEPD during the three months ended March 31, 2015, of which 14,523 BOPD, or 68 percent, was crude oil, 17 percent was NGLs and 15 percent was natural gas. The sequential decline in production was due primarily to higher gathering line pressures and lower than expected initial production performance of our recent Upper Eagle Ford, or Marl, program. Higher line pressure curtailed production by an estimated 500 BOEPD during the first six months of 2015. We anticipate that this issue will be resolved in the third quarter of 2015 as our midstream transporter is adding additional compression.

During the three months ended June 30, 2015, we completed and turned in line 19 gross (13.5 net) wells in the Eagle Ford for a total of 46 gross (27.6 net) wells on a year-to-date basis. Average well costs for all wells drilled and completed during the three months ended June 30, 2015 declined by approximately $1.7 million, or 19 percent, to $6.9 million from approximately $8.6 million for wells drilled and completed in the first quarter of 2015. This lower overall well cost equates to an approximate 30 percent decrease in well costs since the fourth quarter of 2014 and approximately a 42 percent reduction since the third quarter of 2014. More specifically, the cost of our most recent two-string Lower Eagle Ford wells averaged $5.3 million, while our most recent three-string wells averaged $8.0 million.

Average drilling costs for the three months ended June 30, 2015 decreased 24 percent and 30 percent, respectively, compared to the fourth and third quarters of 2014 due primarily to efficiencies and increased average rates of penetration. Average completion costs for wells over those same time intervals declined by 34 percent and 51 percent, respectively. Approximately half of the cost reduction can be attributed to ongoing optimization and increased efficiencies associated with stimulation design while the remainder is associated with improved vendor pricing for services and materials.

Despite disappointing initial production rates of some of our recent Marl wells, we continue to believe that the Marl has significant potential across much of our acreage. Furthermore, we have identified certain factors which we believe contributed to our recent less-than-expected well results in the Marl. First, in the second quarter of 2015, we reduced the amount of proppant pumped per foot of lateral. Analysis has yielded compelling evidence that there is a positive correlation between the amount of proppant pumped and well performance, so we intend to increase proppant in the third quarter. In addition, we have drilled, with favorable results, some Marl wells in the general vicinity of other wells that had disappointing results, with the difference being that the better-performing wells had alternating laterals in the Marl and Lower Eagle Ford that were then “zipper” fracked. Finally, we intend to transition to “slickwater” stimulations. We believe that using this combination of a more complex completion technique of alternating laterals, increasing proppant pumped per stage and transitioning to slickwater stimulations will improve our well results. For the remainder of 2015, while our capital resources are constrained in the current economic environment of continued low oil prices, we are discontinuing Marl drilling and are focusing our efforts on drilling less costly two-string Lower Eagle Ford wells in Gonzales County and northwestern Lavaca County where, based on our experience, we expect better rates of return. Preliminarily, we expect to resume multi-well pad drilling of alternating Marl and Lower Eagle Ford wells in 2016.

The properties to be sold had net production of 1,898 BOEPD during the second quarter of 2015, consisting of 74 percent natural gas, 19 percent NGLs and seven percent crude oil. As a result of the divestiture, reported 2015 production is expected to decrease by an estimated 200 MBOE. Estimated proved reserves associated with the properties at year-end 2014, as determined by third party engineers, were 13.7 MMBOE, 85 percent of which were proved developed. The reserves consisted of 77 percent natural gas, 16 percent NGLs and six percent crude oil.

In May 2015, the Revolver was amended to decrease the revolving commitment and borrowing base to $425 million from $450 and $500 million, respectively, in connection with our regular semi-annual redetermination. The decrease was due primarily to substantial declines in commodity prices, partially offset by development of proved undeveloped locations. In addition, the amendment increased the existing leverage ratio (total debt to EBITDAX, a non-GAAP measure) covenant for the remainder of its term, limited certain restricted payments and added a covenant with respect to outstanding borrowings and letters of credit under the Revolver. Please read “Financial Condition – Capitalization: Covenant Compliance” regarding the specific covenants and “Financial Condition – Liquidity” regarding potential future covenant compliance issues.



	Total Production				Average Daily Production
	Three Months Ended				Three Months Ended
	June 30,		2015 vs.		June 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(Total volume)				(Volume per day)
Crude oil (MBbl and Bbl per day)	1,280	1,119	161		14,064	12,298	1,767
NGLs (MBbl and Bbl per day)	384	261	123		4,217	2,863	1,354
Natural gas (MMcf and MMcf per day)	2,860	3,618	(758	)	31	40	(8	)
Total (MBOE and BOE per day)	2,140	1,983	158		23,519	21,786	1,732
% Change							8	%
	Three Months Ended				Three Months Ended
	June 30,		2015 vs.		June 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBOE)				(BOE per day)
Texas
South Texas	1,844	1,421	422		20,259	15,618	4,641
East Texas	173	220	(47	)	1,898	2,417	(519	)
Mid-Continent	119	161	(43	)	1,302	1,770	(467	)
Other ¹	5	180	(175	)	59	1,981	(1,922	)
	2,140	1,983	158		23,519	21,786	1,732

	Six Months Ended				Six Months Ended
	June 30,		2015 vs.		June 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(Total volume)				(Volume per day)
Crude oil (MBbl and Bbl per day)	2,617	2,195	422		14,458	12,127	2,330
NGLs (MBbl and Bbl per day)	781	488	293		4,312	2,694	1,618
Natural gas (MMcf and MMcf per day)	5,806	7,211	(1,405	)	32	40	(8	)
Total (MBOE and BOE per day)	4,365	3,885	481		24,116	21,461	2,655
% Change							12	%
	Six Months Ended				Six Months Ended
	June 30,		2015 vs.		June 30,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBOE)				(BOE per day)
Texas
South Texas	3,769	2,750	1,019		20,822	15,192	5,629
East Texas	346	435	(89	)	1,912	2,406	(494	)
Mid-Continent	239	335	(95	)	1,322	1,850	(527	)
Other ¹	11	364	(353	)	61	2,014	(1,953	)
	4,365	3,885	481		24,117	21,461	2,655

Total production increased during the three and six months ended June 30, 2015 compared to the corresponding periods of 2014 due primarily to the continued development of our Eagle Ford assets in South Texas. The increase was partially offset by natural production declines in our East Texas and Mid-Continent regions as well as the sale of our Mississippi Selma Chalk assets in July 2014. Approximately 78 percent of total production during both the three and six months ended June 30, 2015 was attributable to oil and NGLs, representing increases of approximately 21 percent and 27 percent, respectively, over the prior year periods. During both the three and six months ended June 30, 2015, our Eagle Ford production represented approximately 86 percent of our total production compared to approximately 72 percent and 71 percent, respectively, from this play during the corresponding periods of 2014.



	Three Months Ended							Three Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Unit of volume)
Crude oil (Total revenue and $ per barrel)	$	70,672	$	112,090	$	(41,418	)	$	55.22	$	100.16	$	(44.94	)
NGLs (Total revenue and $ per barrel)	5,191		8,037		(2,846		)	13.53		30.85		(17.32		)
Natural gas (Total revenue and $ per Mcf))	7,260		16,302		(9,042		)	2.54		4.51		(1.97		)
Total (Total revenue and $ per BOE)	$	83,123	$	136,429	$	(53,306	)	$	38.84	$	68.81	$	(29.97	)
% Change												(39		)%

	Three Months Ended							Three Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per BOE)
Texas
South Texas	$	77,463	$	116,525	$	(39,062	)	$	42.02	$	81.99	$	(39.97	)
East Texas	3,019		7,290		(4,271		)	17.48		33.14		(15.66		)
Mid-Continent	2,599		7,529		(4,930		)	21.93		46.75		(24.82		)
Other	42		5,085		(5,043		)	7.79		28.20		(20.41		)
	$	83,123	$	136,429	$	(53,306	)	$	38.84	$	68.81	$	(29.98	)

	Six Months Ended							Six Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Unit of volume)
Crude oil (Total revenue and $ per barrel)	$	129,840	$	217,666	$	(87,826	)	$	49.62	$	99.16	$	(49.54	)
NGLs (Total revenue and $ per barrel)	10,587		17,410		(6,823		)	13.56		35.71		(22.14		)
Natural gas (Total revenue and $ per Mcf))	15,831		34,505		(18,674		)	2.73		4.78		(2.06		)
Total (Total revenue and $ per BOE)	$	156,258	$	269,581	$	(113,323	)	$	35.80	$	69.40	$	(33.60	)
% Change												(42		)%

	Six Months Ended							Six Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per BOE)
Texas
South Texas	$	144,328	$	226,920	$	(82,592	)	$	38.30	$	82.52	$	(44.22	)
East Texas	6,341		15,971		(9,630		)	18.33		36.68		(18.35		)
Mid-Continent	5,477		15,993		(10,516		)	22.88		47.77		(24.88		)
Other	112		10,697		(10,585		)	10.14		29.35		(19.21		)
	$	156,258	$	269,581	$	(113,323	)	$	35.80	$	69.40	$	(33.60	)



	Three Months Ended 2015 vs. 2014									Six Months Ended 2015 vs. 2014
	Revenue Variance Due to									Revenue Variance Due to
	Volume			Price			Total			Volume			Price			Total
Crude oil	$	16,099		$	(57,517	)	$	(41,418	)	$	41,826		$	(129,652	)	$	(87,826	)
NGL	3,802			(6,648		)	(2,846		)	10,459			(17,282		)	(6,823		)
Natural gas	(3,416		)	(5,626		)	(9,042		)	(6,722		)	(11,952		)	(18,674		)
	$	16,485		$	(69,791	)	$	(53,306	)	$	45,563		$	(158,886	)	$	(113,323	)

In the three and six months ended June 30, 2015, we received $34.8 million and $72.3 million, respectively, in cash settlements of oil and gas derivatives. In the three and six months ended June 30, 2014, we paid cash settlements of oil and gas derivatives of $7.2 million and $10.3 million, respectively. The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Three Months Ended								Six Months Ended
	June 30,					2015 vs.			June 30,					2015 vs.
	2015		2014			2014			2015		2014			2014
						Favorable (unfavorable)								Favorable (unfavorable)
Crude oil revenues as reported	$	70,672	$	112,090		$	(41,418	)	$	129,840	$	217,666		$	(87,826	)
Derivative settlements, net	34,840		(6,087		)	40,927			71,651		(8,365		)	80,016
	$	105,512	$	106,003		$	(491	)	$	201,491	$	209,301		$	(7,810	)

Crude oil prices per Bbl, as reported	$	55.22	$	100.16		$	(44.94	)	$	49.62	$	99.16		$	(49.54	)
Derivative settlements per Bbl	27.22		(5.44		)	32.67			27.38		(3.81		)	31.20
	$	82.44	$	94.72		$	(12.27	)	$	77.00	$	95.35		$	(18.34	)

Natural gas revenues as reported	$	7,260	$	16,302		$	(9,042	)	$	15,831	$	34,505		$	(18,674	)
Derivative settlements, net	—		(1,135		)	1,135			681		(1,914		)	2,595
	$	7,260	$	15,167		$	(7,907	)	$	16,512	$	32,591		$	(16,079	)

Natural gas prices per Mcf, as reported	$	2.54	$	4.51		$	(1.97	)	$	2.73	$	4.78		$	(2.06	)
Derivative settlements per Mcf	—		(0.31		)	0.31			0.12		(0.27		)	0.38
	$	2.54	$	4.20		$	(1.65	)	$	2.85	$	4.51		$	(1.68	)

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

Lease operating expense decreased during the three months ended June 30, 2015 on an absolute basis compared to the corresponding period of 2014 due primarily to the sale of our Mississippi assets in July 2014. Lease operating expenses also decreased on a per-unit basis during this period due primarily to costs in our South Texas region being spread over higher production volumes. We incurred higher workover and subsurface maintenance costs in both South and East Texas during the three and six months ended June 30, 2015 which was the primary cause of the unfavorable variance for the six-month period on an absolute basis, but the increase in South Texas production volumes resulted in lower per-unit operating costs.



	Three Months Ended							Six Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
					Favorable (unfavorable)							Favorable (unfavorable)
Gathering, processing and transportation	$	6,383	$	3,928	$	(2,455	)	$	13,881	$	7,177	$	(6,704	)
Per unit of production ($/BOE)	$	2.98	$	1.98	$	(1.00	)	$	3.18	$	1.85	$	(1.33	)
% Change per unit of production					(51		)%					(72		)%

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



	Three Months Ended									Six Months Ended
	June 30,						2015 vs.			June 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	3,811		$	5,524		$	1,713		$	7,057		$	11,894		$	4,837
Ad valorem taxes	1,156			1,986			830			2,599			2,921			322
	$	4,967		$	7,510		$	2,543		$	9,656		$	14,815		$	5,159
Per unit production ($/BOE)	$	2.32		$	3.79		$	1.47		$	2.21		$	3.81		$	1.60
% Change per unit of production							39		%							42		%
Production/severance tax rate as a percent of product revenue	4.6		%	4.0		%				4.5		%	4.4		%

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

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



	Three Months Ended									Six Months Ended
	June 30,						2015 vs.			June 30,				2015 vs.
	2015			2014			2014			2015		2014		2014
							Favorable (unfavorable)							Favorable (unfavorable)
Recurring general and administrative expenses	$	9,823		$	11,846		$	2,023		$	20,435	$	21,545	$	1,110
Share-based compensation (liability-classified)	(214		)	1,047			1,261			165		6,992		6,827
Share-based compensation (equity-classified)	1,116			826			(290		)	2,106		1,651		(455		)
Significant non-recurring expenses:
Acquisition-related arbitration costs	—			380			380			—		587		587
ERP system development costs	—			744			744			—		744		744
Restructuring expenses	754			(3		)	(757		)	743		9		(734		)
Total general and administrative expenses	$	11,479		$	14,840		$	3,361		$	23,449	$	31,528	$	8,079
Per unit of production ($/BOE)	$	5.36		$	7.48		$	2.12		$	5.37	$	8.12	$	2.75
% Change per unit of production							28		%					34		%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	4.94		$	6.54		$	1.60		$	4.85	$	5.89	$	1.04
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	4.59		$	5.97		$	1.38		$	4.68	$	5.55	$	0.87

Our total general and administrative expenses decreased on both an absolute and per-unit basis during the three and six months ended June 30, 2015 compared to the corresponding periods of 2014. Decreases in recurring general and administrative expenses were attributable primarily to lower employee headcount and lower cash-based incentive compensation. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the change in fair value of the outstanding PBRSU grants. Our common stock performance relative to a defined peer group was less favorable during the 2015 periods resulting in a reduction in liability-classified share-based compensation. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, increased during the three and six months ended June 30, 2015 due primarily to a change in the mix of grant-date vesting provisions for certain awards. During the 2014 periods, we incurred costs (including legal and litigation support fees) attributable to arbitration proceedings associated with a 2013 acquisition. We also incurred certain costs in the 2014 periods not eligible for capitalization, including post-implementation support and training with respect to our ERP system. In connection with our ongoing efforts to adjust the scale of our administrative cost structure, we terminated 18 employees and paid termination and severance benefits of $0.8 million during the three months ended June 30, 2015.

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



	Three Months Ended							Six Months Ended
	June 30,				2015 vs.			June 30,				2015 vs.
	2015		2014		2014			2015		2014		2014
					Favorable (unfavorable)							Favorable (unfavorable)
Unproved leasehold amortization	$	2,022	$	3,285	$	1,263		$	4,005	$	6,579	$	2,574
Drilling rig termination charges	2,040		—		(2,040		)	5,665		—		(5,665		)
Geological and geophysical (seismic) costs	219		80		(139		)	506		4,580		4,074
Other, primarily delay rentals	81		8		(73		)	73		850		777
	$	4,362	$	3,373	$	(989	)	$	10,249	$	12,009	$	1,760

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



	Three Months Ended									Six Months Ended
	June 30,						2015 vs.			June 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
DD&A expense	$	85,416		$	71,437		$	(13,979	)	$	176,206		$	143,624		$	(32,582	)
DD&A rate ($/BOE)	$	39.91		$	36.03		$	(3.88	)	$	40.37		$	36.97		$	(3.40	)

	Production			Rates			Total			Production			Rates			Total
DD&A variance due to:	$	(5,656	)	$	(8,323	)	$	(13,979	)	$	(17,745	)	$	(14,837	)	$	(32,582	)

We recorded an impairment charge of $1.1 million attributable to surplus tubular inventory and well materials during the three months ended June 30, 2015. We anticipate selling certain of these materials on the surplus market in the second half of 2015. In June 2014, we recorded an impairment charge of $117.9 million to write down the value of our Selma Chalk assets in Mississippi to their fair value in advance of their sale in July 2014.



	Three Months Ended									Six Months Ended
	June 30,						2015 vs.			June 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
Interest on borrowings and related fees	$	23,324		$	23,778		$	454		$	46,132		$	46,918		$	786
Amortization of debt issuance costs	1,176			1,039			(137		)	2,280			2,051			(229		)
Capitalized interest	(1,477		)	(1,588		)	(111		)	(3,376		)	(3,206		)	170
	$	23,023		$	23,229		$	206		$	45,036		$	45,763		$	727
Weighted-average debt outstanding	$	1,286,304		$	1,304,654					$	1,238,233		$	1,295,225
Weighted average interest rate	7.25		%	7.29		%				7.45		%	7.24		%



	Three Months Ended									Six Months Ended
	June 30,						2015 vs.			June 30,						2015 vs.
	2015			2014			2014			2015			2014			2014
							Favorable (unfavorable)									Favorable (unfavorable)
Oil and gas derivatives settled	$	34,840		$	(7,222	)	$	42,062		$	72,332		$	(10,279	)	$	82,611
Oil and gas derivatives gain (loss)	(50,335		)	(35,443		)	(14,892		)	(64,960		)	(48,048		)	(16,912		)
	$	(15,495	)	$	(42,665	)	$	27,170		$	7,372		$	(58,327	)	$	65,699

We received cash settlements of $34.8 million and $71.7 million, respectively, for crude oil derivatives during the three and six months ended June 30, 2015 and paid settlements of $6.1 million and $8.4 million, respectively, during the three and six months ended June 30, 2014. We had no natural gas derivatives outstanding during the three months ended June 30, 2015. We received natural gas cash settlements of $0.7 million during the six months ended June 30, 2015 and paid settlements of $1.1 million and $1.9 million, respectively, during the three and six months ended June 30, 2014.

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

During 2015, our capital expenditures will exceed our projected cash from operating activities; however, we have no debt maturities until September 2017 when the Revolver matures. The borrowing base under the Revolver is scheduled to be redetermined in the fall of 2015. We expect that such redetermination will result in a further decrease in the borrowing base. Notwithstanding the anticipated borrowing base decrease, we expect that we will be able to fund our capital expenditures as well as meet our debt service requirements, pay our preferred stock dividends and meet our working capital requirements for the remainder of 2015 with cash from operating activities, borrowings under the Revolver and proceeds from the sale of non-core assets, including our East Texas assets, which we have agreed to sell for $75 million with an expected closing date at the end of August 2015.

Without a meaningful improvement in commodity prices, there is a significant possibility that we will exceed the debt leverage covenant under the Revolver in the second quarter of 2016. Consequently, we are currently discussing future covenant relief with the agent bank under the Revolver. There can be no assurance that such relief will be granted. Moreover, unless we can access additional capital through public or private debt or equity capital markets, or by selling additional assets, we would likely need to curtail our currently contemplated drilling program in 2016.

In 2015, we anticipate making capital expenditures of up to approximately $345 million. We expect to allocate substantially all of our capital expenditures to the Eagle Ford. This includes approximately 93 percent for drilling and completions, four percent for leasehold acquisition and three percent for facilities and other projects. Our business plan for the remainder of 2015 assumes a drilling program utilizing two operated drilling rigs through July with a reduction to a single rig in August 2015. We anticipate that we will incur an early termination charge of approximately $1.3 million in connection with the release of this rig. We continually review our drilling and capital expenditure plans and may change the amount we spend, or the allocations, based on available opportunities, product pricing, industry conditions, cash from operating activities and the overall availability of capital. For a detailed analysis of our historical capital expenditures, see the Cash Flows discussion that follows.

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

We actively manage the exposure of our revenues to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production, typically through the use of collar and swap contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices, the magnitude of our capital program and our operating strategy. During the six months ended June 30, 2015, our commodity derivatives portfolio resulted in $71.7 million and $0.7 million of net cash receipts related to lower than anticipated prices received for our crude oil and natural gas production, respectively. If commodity prices remain depressed, we anticipate that our derivative portfolio will continue to result in receipts from settlements for the remainder of 2015.

We have hedged approximately 11,000 BOPD, or approximately 80 to 90 percent of our expected crude oil production during the second half of 2015, at a weighted-average floor/swap price of $89.86 per barrel. For 2016, we have hedged approximately 6,000 BOPD at weighted-average swap price of $80.41 per barrel. Certain crude oil derivative transactions include put options we sold. All of the put options carry a $70.00 strike price. If the price of WTI Crude Oil settles below $70.00 per barrel for any given measurement period, the cash received by us on the derivative settlement will be limited to the difference between the floor/swap price and the $70.00 put option strike price. The sum of the notional volumes attached to the put options is 5,000 barrels per day for the third and fourth quarters of 2015. Our natural gas hedges have expired and we anticipate remaining unhedged with respect to natural gas production for the remainder of 2015.

Revolver Borrowings. The Revolver provides for a revolving commitment and borrowing base of $425 million. The Revolver has an accordion feature that allows us to increase the commitment by up to an additional $175 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation, which is re-determined semi-annually, and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The next semi-annual redetermination is scheduled for November 2015 although we expect the borrowing base to be reduced by approximately $30 million prior to the redetermination upon the closing of the sale of our East Texas assets.

Proceeds from Sales of Assets. We continually evaluate potential sales of non-core assets, including certain oil and gas properties and non-strategic undeveloped acreage, among others. In July 2015, we entered into an agreement to sell our Haynesville Shale and Cotton Valley assets in East Texas for gross cash proceeds of $75 million. The sale is expected to close by the end of August 2015 and is subject to customary purchase price adjustments and other customary closing conditions.



	Six Months Ended
	June 30,
	2015			2014			Variance
Cash flows from operating activities
Operating cash flows, net	$	91,643		$	195,262		$	(103,619	)
Working capital changes (excluding interest, income taxes and restructuring costs paid), net	(14,661		)	(39,407		)	24,746
Commodity derivative settlements received (paid), net:
Crude oil	71,651			(8,365		)	80,016
Natural gas	681			(1,914		)	2,595
Interest payments, net of amounts capitalized	(42,665		)	(43,828		)	1,163
Income taxes paid	(7		)	(100		)	93
Drilling rig termination charges paid	(6,416		)	—			(6,416		)
ERP system development costs paid	—			(744		)	744
Acquisition arbitration and other costs paid	—			(587		)	587
Restructuring and exit costs paid	(1,945		)	(1,124		)	(821		)
Net cash provided by operating activities	98,281			99,193			(912		)
Cash flows from investing activities
Capital expenditures – property and equipment	(263,993		)	(350,580		)	86,587
Proceeds from sales of assets, net	(221		)	96,632			(96,853		)
Net cash used in investing activities	(264,214		)	(253,948		)	(10,266		)
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 (repayments) from revolving credit facility borrowings, net	177,000			(151,000		)	328,000
Debt issuance costs paid	(744		)	(151		)	(593		)
Dividends paid on preferred stock	(12,134		)	(3,836		)	(8,298		)
Other, net	—			1,085			(1,085		)
Net cash provided by financing activities	164,122			156,376			7,746
Net (decrease) increase in cash and cash equivalents	$	(1,811	)	$	1,621		$	(3,432	)

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

Cash Flows From Investing Activities. Cash paid for capital expenditures was lower during the six months ended June 30, 2015 compared to the corresponding period during 2015 due primarily to a substantial reduction in our capital program including reductions in the number of operating drilling rigs and well completion and frac crews. Our capital expenditures during the 2014 period were partially offset by the receipt of net proceeds from the sale of our natural gas gathering and gas lift assets in South Texas in January 2014.



	Six Months Ended
	June 30,
	2015		2014
Oil and gas:
Drilling and completion	$	222,223	$	289,500
Lease acquisitions and other land-related costs¹	14,072		49,667
Pipeline, gathering facilities and other equipment	3,561		7,187
Geological, geophysical (seismic) and delay rental costs	579		4,580
	240,435		350,934
Other – Corporate	438		972
Total capital program costs	$	240,873	$	351,906

______________________



	Six Months Ended
	June 30,
	2015			2014
Total capital program costs	$	240,873		$	351,906
Decrease in accrued capitalized costs	20,570			858
Less:
Exploration costs charged to operations:
Geological, geophysical (seismic) and delay rental costs	(579		)	(5,360		)
Transfers from tubular inventory and well materials	(2,414		)	(409		)
Add:
Tubular inventory and well materials purchased in advance of drilling	2,167			379
Capitalized interest	3,376			3,206
Total cash paid for capital expenditures	$	263,993		$	350,580

Cash Flows From Financing Activities. Cash flows from financing activities for the six months ended June 30, 2015 included net borrowings of $177 million under the Revolver used to fund a portion of our capital expenditures while the 2014 period included net repayments of $151 million sourced primarily by the offering of our 6% Series B Convertible Perpetual Preferred Stock, or Series B Preferred Stock, and the net proceeds from the sale of our South Texas natural gas gathering and gas lift assets. We paid total dividends of $12.1 million for the 6% Series A Convertible Perpetual Preferred Stock, or Series A Preferred Stock, and the Series B Preferred Stock during the six months ended June 30, 2015. Dividends of $3.8 million were paid during the comparable period in 2014 on the Series A Preferred Stock as well as $3.4 million of payments to induce the conversion of 2,620 of the outstanding shares of the Series A Preferred Stock. We paid issuance costs associated with amendments to the Revolver during both the 2015 and 2014 periods including $0.7 million in the 2015 period in connection with the revised commitment, borrowing base and covenant amendment and $0.2 million in the 2014 period in advance of the Series B Preferred Stock offering. We also received proceeds of $1.1 million during the 2014 period from the exercise of stock options.

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin (ranging from 1.500% to 2.500%) or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, plus, in each case, an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. As of June 30, 2015, the actual interest rate applicable to the Revolver was 2.1875%, which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 2.00%. 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, 2015, commitment fees were being charged at a rate of 0.500%.

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% and are payable on April 15 and October 15 of each year. We may redeem all or part of the 2019 Senior Notes at a redemption price of 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2020 Senior Notes. The 8.50% Senior Notes due 2020, or the 2020 Senior Notes, which were issued at par in April 2013, bear interest at an annual rate of 8.50% and are payable on May 1 and November 1 of each year. Beginning in May 2017, we may redeem all or part of the 2020 Senior Notes at a redemption price of 104.250% of the principal amount and reducing to 100% in May 2019 and thereafter. The 2020 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The 2020 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Series A and Series B Preferred Stock. The annual dividend on each share of the Series A and Series B Preferred Stock is 6.00% per annum on the liquidation preference of $10,000 per share and is payable quarterly, in arrears, on each of January 15, April 15, July 15 and October 15 of each year. We may, at our option, pay dividends in cash, common stock or a combination thereof; however, the utilization of common stock to pay dividends on the Series B Preferred Stock would require shareholder approval. In addition, cash payment of dividends may be limited by certain financial covenants under the Revolver (see Covenant Compliance that follows).

Each share of the Series A and Series B Preferred Stock is convertible, at the option of the holder, into a number of shares of our common stock equal to the liquidation preference of $10,000 divided by the conversion prices, which is initially $6.00 per share for the series A Preferred Stock and $18.34 per share for the Series B Preferred Stock and both series are subject to specified anti-dilution adjustments. The initial conversion rate is equal to 1,666.67 shares of our common stock for each share of the Series A Preferred Stock and 545.17 shares for each share of the Series B Preferred Stock. The Series A and Series B Preferred Stock are not redeemable for cash by us or the holders at any time. At any time on or after October 15, 2017 in the case of the Series A Preferred Stock and July 15, 2019 in the case of the Series B Preferred Stock, we may, at our option, cause all outstanding shares of the Series A and Series B Preferred Stock, respectively, to be automatically converted into shares of our common stock at the then-applicable conversion prices for each series if the closing sale price of our common stock exceeds 130% of the then-applicable conversion prices for a specified period prior to conversion. If a holder elects to

Covenant Compliance. The Revolver and the indentures governing our senior notes require us to maintain certain financial and non-financial covenants. These covenants impose limitations on our ability to pay dividends as well as our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries, among other requirements.

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

The process of preparing financial statements in accordance with U.S. GAAP requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Disclosure of our most critical accounting estimates that involve the judgment of our management can be found in our Annual Report on Form 10-K for the year ended December 31, 2014.

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs, or ASU 2015–03, on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes, which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7 to the Condensed Consolidated Financial Statements) for all periods presented. Issuance costs associated with the Revolver continue to be presented, net of amortization, as a component of Other assets (see Note 10 to the Condensed Consolidated Financial Statements).

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.

All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Accordingly, our interest rate risk is attributable to our borrowings under the Revolver, which is subject to variable interest rates. As of June 30, 2015, we had borrowings of $212 million under the Revolver at an interest rate of 2.1875%. Assuming a constant borrowing level of $212 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) of approximately $2.1 million on an annual basis.

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

As of June 30, 2015, our commodity derivative portfolio was in a net asset position. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with four of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions.

During the six months ended June 30, 2015, we reported net commodity derivative gains of $7.4 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.



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Third quarter 2015	Collars	3,000	$	86.67	$	94.73	$	5,484	$	—
Fourth quarter 2015	Collars	3,000	$	86.67	$	94.73	5,186		—
Third quarter 2015	Swaps	8,000	$	91.06			20,056		—
Fourth quarter 2015	Swaps	8,000	$	91.06			19,238		—
First quarter 2016	Swaps	6,000	$	80.41			10,273		—
First quarter 2016	Swaps	6,000	$	80.41			10,011		—
First quarter 2016	Swaps	6,000	$	80.41			9,911		—
First quarter 2016	Swaps	6,000	$	80.41			9,635		—
Settlements to be received in subsequent period							10,125		—

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.

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, 2015. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 2015, such disclosure controls and procedures were effective.



(3.1)	Articles of Amendment of Restated Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Registrant’s Current Report on Form 8-K filed on May 14, 2015).

(10.1)	Ninth Amendment and Borrowing Base Redetermination Agreement dated as of May 7, 2015, 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 the Registrant’s Current Report on Form 8-K filed on May 11, 2015).

(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



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



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



	As of
	June 30,			December 31,
	2015			2014
Customers	$	59,906		$	62,650
Joint interest partners	39,412			120,708
Other	5,873			6,549
	105,191			189,907
Less: Allowance for doubtful accounts	(555		)	(280		)
	$	104,636		$	189,627



	As of
	June 30,			December 31,
	2015			2014
Oil and gas properties:
Proved	$	3,625,962		$	3,390,482
Unproved	128,317			125,676
Total oil and gas properties	3,754,279			3,516,158
Other property and equipment	76,719			75,073
Total properties and equipment	3,830,998			3,591,231
Accumulated depreciation, depletion and amortization	(1,942,106		)	(1,766,133		)
	$	1,888,892		$	1,825,098



	As of
	June 30,			December 31,
	2015			2014
Balance at beginning of period	$	14,790		$	15,993
Accretion	445			1,301
Cash payments, net	(1,089		)	(2,504		)
Balance at end of period	$	14,146		$	14,790



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



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


•	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.


•	the volatility of commodity prices for oil, natural gas liquids, or NGLs and natural gas;


•	our ability to develop, explore for, acquire and replace oil and natural gas reserves and sustain production;


•	our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;


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


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


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


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


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


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


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


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


•	leasehold terms expiring before production can be established;


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


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


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


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


•	other factors set forth in our periodic filings with the Securities and Exchange Commission, including the risks set forth in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014.


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


¹	Comprised of our three active Marcellus Shale wells in Pennsylvania and, for periods through July 2014, our divested Selma Chalk assets in Mississippi.



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended June 30, 2015	$	217,099	$	232,000	2.1190	%
Six months ended June 30, 2015	$	171,972	$	232,000	2.0283	%


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


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



	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.75 to 1	3.7 to 1
Credit exposure to EBITDAX	< 2.75 to 1	0.6 to 1
Current ratio	> 1.00 to 1	1.7 to 1
Interest coverage	> 2.25 to 1	3.1 to 1