BAYTEX ENERGY USA, INC. - Quarter Report: 2015 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________________________________________________

FORM 10-Q

________________________________________________________

(Mark One)



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

For the quarterly period ended March 31, 2015



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

For the transition period from to

Commission file number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

__________________________________________________________



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

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

__________________________________________________________

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

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

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



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

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

As of May 7, 2015, 71,656,744 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

QUARTERLY REPORT ON FORM 10-Q

For the Quarterly Period Ended March 31, 2015

Table of Contents



Part I - Financial Information
Item		Page
1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended March 31, 2015 and 2014	3
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended March 31, 2015 and 2014	4
	Condensed Consolidated Balance Sheets as of March 31, 2015 and December 31, 2014	5
	Condensed Consolidated Statements of Cash Flows for the Periods Ended March 31, 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	12
	9. Firm Transportation Obligation	12
	10. Additional Balance Sheet Detail	13
	11. Fair Value Measurements	13
	12. Commitments and Contingencies	15
	13. Shareholders' Equity	16
	14. Share-Based Compensation	16
	15. Interest Expense	17
	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	21
	Financial Condition	28
	Critical Accounting Estimates	32
3.	Quantitative and Qualitative Disclosures About Market Risk	33
4.	Controls and Procedures	35
Part II - Other Information
1.	Legal Proceedings	36
6.	Exhibits	36
Signatures		37

Part I. FINANCIAL INFORMATION

Item 1. Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)



	Three Months Ended
	March 31,
	2015			2014
Revenues
Crude oil	$	59,168		$	105,576
Natural gas liquids (NGLs)	5,396			9,373
Natural gas	8,571			18,203
Gain (loss) on sales of property and equipment, net	(91		)	56,826
Other, net	1,483			(113		)
Total revenues	74,527			189,865
Operating expenses
Lease operating	11,569			10,116
Gathering, processing and transportation	7,498			3,249
Production and ad valorem taxes	4,689			7,305
General and administrative	11,970			16,688
Exploration	5,887			8,636
Depreciation, depletion and amortization	90,790			72,187
Total operating expenses	132,403			118,181
Operating income (loss)	(57,876		)	71,684
Other income (expense)
Interest expense	(22,013		)	(22,534		)
Derivatives	22,867			(15,662		)
Other	(2		)	1
Income (loss) before income taxes	(57,024		)	33,489
Income tax expense	(141		)	(14,264		)
Net income (loss)	(57,165		)	19,225
Preferred stock dividends	(6,067		)	(1,722		)
Net income (loss) attributable to common shareholders	$	(63,232	)	$	17,503
Net income (loss) per share:
Basic	$	(0.88	)	$	0.27
Diluted	$	(0.88	)	$	0.22

Weighted average shares outstanding – basic	71,820			65,611
Weighted average shares outstanding – diluted	71,820			85,744

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)



	Three Months Ended
	March 31,
	2015			2014
Net income (loss)	$	(57,165	)	$	19,225
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax of $(6) and $13 in 2015 and 2014	(11		)	25
	(11		)	25
Comprehensive income (loss)	$	(57,176	)	$	19,250

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)



	As of
	March 31,			December 31,
	2015			2014
Assets
Current assets
Cash and cash equivalents	$	3,859		$	6,252
Accounts receivable, net of allowance for doubtful accounts	149,929			189,627
Derivative assets	118,409			128,981
Deferred income taxes	—			53
Other current assets	9,687			10,114
Total current assets	281,884			335,027
Property and equipment, net (successful efforts method)	1,880,612			1,825,098
Derivative assets	31,844			35,897
Other assets	4,311			4,218
Total assets	$	2,198,651		$	2,200,240

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	245,066		$	312,227
Derivative liabilities	—			—
Total current liabilities	245,066			312,227
Other liabilities	123,524			123,886
Deferred income taxes	4,587			4,504
Long-term debt, net of unamortized issuance costs	1,211,910			1,083,806

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 March 31, 2015 and December 31, 2014 and Series B – 32,500 shares issued as of March 31, 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 – 128,000,000 shares authorized; 71,594,960 and 71,568,936 shares issued as of March 31, 2015 and December 31, 2014, respectively	529			529
Paid-in capital	1,207,294			1,206,305
Accumulated deficit	(598,408		)	(535,176		)
Deferred compensation obligation	3,267			3,211
Accumulated other comprehensive income	238			249
Treasury stock – 273,564 and 262,070 shares of common stock, at cost, as of March 31, 2015 and December 31, 2014, respectively	(3,400		)	(3,345		)
Total shareholders’ equity	613,564			675,817
Total liabilities and shareholders’ equity	$	2,198,651		$	2,200,240

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)



	Three Months Ended
	March 31,
	2015			2014
Cash flows from operating activities
Net income (loss)	$	(57,165	)	$	19,225
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	90,790			72,187
Accretion of firm transportation obligation	212			354
Derivative contracts:
Net losses (gains)	(22,867		)	15,662
Cash settlements, net	37,492			(3,057		)
Deferred income tax expense	141			14,064
Loss (gain) on sales of assets, net	91			(56,826		)
Non-cash exploration expense	1,983			3,294
Non-cash interest expense	1,104			1,012
Share-based compensation (equity-classified)	990			825
Other, net	9			206
Changes in operating assets and liabilities, net	(7,228		)	(386		)
Net cash provided by operating activities	45,552			66,560

Cash flows from investing activities
Capital expenditures – property and equipment	(168,994		)	(159,804		)
Proceeds from sales of assets, net	116			95,964
Net cash used in investing activities	(168,878		)	(63,840		)

Cash flows from financing activities
Proceeds from revolving credit facility borrowings	127,000			85,000
Repayment of revolving credit facility borrowings	—			(101,000		)
Dividends paid on preferred stock	(6,067		)	(1,725		)
Other, net	—			1,085
Net cash provided by (used in) financing activities	120,933			(16,640		)
Net decrease in cash and cash equivalents	(2,393		)	(13,920		)
Cash and cash equivalents – beginning of period	6,252			23,474
Cash and cash equivalents – end of period	$	3,859		$	9,554

Supplemental disclosures:
Cash paid for:
Interest	$	732		$	1,025
Income taxes	$	—		$	—

See accompanying notes to condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended March 31, 2015

(in thousands, except per share amounts)


1.	Organization

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


2.	Basis of Presentation

Our unaudited Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of our subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”). Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2014. Operating results for the three months ended March 31, 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 and revolving credit facility (the “Revolver”), which were formerly presented as a component of Other assets, as a reduction to Long-term debt (see Note 7) for all periods presented.

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 in connection with an amendment to our Revolver as discussed in Note 7, no subsequent events have occurred that would require recognition in our Condensed Consolidated Financial Statements or disclosure in the Notes to Condensed Consolidated Financial Statements.


3.	Divestitures

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 $0.1 million of the deferred gain during each of the three months ended March 31, 2015 and 2014, respectively. As of March 31, 2015, $0.4 million of the remaining deferred gain is included as a component of Accounts payable and accrued expenses and $9.7 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 March 31, 2015, $3.4 million of the deferred gain is included as a component of Accounts payable and accrued expenses and $80.7 million, representing the noncurrent portion, is included as a component of Other liabilities on our Condensed Consolidated Balance Sheets.

4. Accounts Receivable and Major Customers

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



	As of
	March 31,			December 31,
	2015			2014
Customers	$	57,125		$	62,650
Joint interest partners	86,297			120,708
Other	6,787			6,549
	150,209			189,907
Less: Allowance for doubtful accounts	(280		)	(280		)
	$	149,929		$	189,627

For the three months ended March 31, 2015, three customers accounted for $47.9 million, or approximately 66%, of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2015 were $28.0 million, $12.0 million and $7.9 million or 38%, 17% and 11% of the consolidated total, respectively. As of March 31, 2015, $27.4 million, or approximately 48% of our consolidated accounts receivable from customers was related to these customers. For the three months ended March 31, 2014, four customers accounted for $89.5 million, or approximately 67% of our consolidated product revenues. The revenues generated from these customers during the three months ended March 31, 2014 were $38.8 million, $17.4 million, $17.2 million and $16.1 million or approximately 29%, 13%, 13% and 12% 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.


5.	Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to crude oil and natural gas price volatility. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

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

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

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

The following table sets forth our commodity derivative positions as of March 31, 2015:



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2015 ¹	Collars	4,000	$	87.50	$	94.66	$	10,045	$	—
Third quarter 2015 ¹	Collars	3,000	$	86.67	$	94.73	6,063		—
Fourth quarter 2015 ¹	Collars	3,000	$	86.67	$	94.73	5,738		—
Second quarter 2015 ¹	Swaps	9,000	$	91.81			27,053		—
Third quarter 2015 ¹	Swaps	8,000	$	91.06			23,139		—
Fourth quarter 2015 ¹	Swaps	8,000	$	91.06			21,918		—
First quarter 2016	Swaps	4,000	$	88.12			11,392		—
Second quarter 2016	Swaps	4,000	$	88.12			10,933		—
Third quarter 2016	Swaps	4,000	$	88.12			10,649		—
Fourth quarter 2016	Swaps	4,000	$	88.12			10,262		—

Settlements to be received in subsequent period							13,061		—

_______________________

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 short puts is 6,000 barrels per day for the second quarter of 2015, and 5,000 barrels per day for the third and fourth quarters of 2015.

Financial Statement Impact of Derivatives

The impact of our derivatives activities on income is included in the Derivatives caption on our Condensed Consolidated Statements of Operations. The following table summarizes the effects of our derivative activities for the periods presented:



	Three Months Ended
	March 31,
	2015			2014
Cash settlements and gains (losses):
Cash (paid) received for:
Commodity contract settlements	$	37,492		$	(3,057	)
Losses attributable to:
Commodity contracts	(14,625		)	(12,605		)
	$	22,867		$	(15,662	)

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

The following table summarizes the fair values of our derivative instruments, as well as the locations of these instruments on our Condensed Consolidated Balance Sheets as of the dates presented:



		Fair Values as of
		March 31, 2015				December 31, 2014
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities – current	$	118,409	$	—	$	128,981	$	—
Commodity contracts	Derivative assets/liabilities – noncurrent	31,844		—		35,897		—
		$	150,253	$	—	$	164,878	$	—

As of March 31, 2015, we reported a commodity derivative asset of $150.3 million. The contracts associated with this position are with seven counterparties, all of which are investment grade financial institutions, and are substantially concentrated with five of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have neither paid to, nor received from, our counterparties any cash collateral in connection with our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.


6.	Property and Equipment

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



	As of
	March 31,			December 31,
	2015			2014
Oil and gas properties:
Proved	$	3,533,859		$	3,390,482
Unproved	127,504			125,676
Total oil and gas properties	3,661,363			3,516,158
Other property and equipment	76,058			75,073
Total properties and equipment	3,737,421			3,591,231
Accumulated depreciation, depletion and amortization	(1,856,809		)	(1,766,133		)
	$	1,880,612		$	1,825,098


7.	Long-Term Debt

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



	As of
	March 31, 2015				December 31, 2014
	Principal		Unamortized Issuance Costs		Principal		Unamortized Issuance Costs
Revolving credit facility	$	162,000	$	1,476	$	35,000	$	1,623
Senior notes due 2019	300,000		3,928		300,000		4,131
Senior notes due 2020	775,000		19,686		775,000		20,440
Totals	1,237,000		$	25,090	1,110,000		$	26,194
Long-term debt, net of unamortized issuance costs	$	1,211,910			$	1,083,806

Revolving Credit Facility

In May 2015, in connection with our regular semi-annual redetermination, the Revolver was amended to decrease the revolving commitment to $425 million from $450 million and to decrease the borrowing base to $425 million from $500 million. The decrease was due primarily to substantial declines in commodity prices partially offset by development of proved undeveloped locations. The next semi-annual redetermination is scheduled for November 2015. 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 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 March 31, 2015. As of March 31, 2015, our available borrowing capacity under the Revolver was $286.2 million before giving effect to the reduced commitment and borrowing base.

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 March 31, 2015, the actual interest rate on the outstanding borrowings under the Revolver was 1.9375%, which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of March 31, 2015, commitment fees were being charged at a rate of 0.375%.

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

The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. In May 2015, the Revolver was amended to increase the leverage ratio, defined in the Revolver as the ratio of total debt to EBITDAX, that, 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, the amendment precludes the payment of cash dividends on our outstanding convertible preferred stock if the total debt to EBITDAX ratio exceeds 5.0 to 1.0. In addition, the Revolver was amended to require a credit exposure leverage covenant, defined in the Revolver as the ratio of credit exposure to EBITDAX, that, 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 credits.

2019 Senior Notes

Our 7.25% Senior Notes due 2019 (the “2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% 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 starting at 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are subordinated to our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2020 Senior Notes

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

Guarantees

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


8.	Income Taxes

Due to the pre-tax operating loss incurred, we recognized a federal income tax benefit for the three months ended March 31, 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%. 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 recognized income tax expense for the three months ended March 31, 2014 at an effective rate of 42.6% which reflects the adverse effects of losses incurred in jurisdictions for which we may not realize a tax benefit and therefore recorded a valuation allowance against the related deferred tax assets.


9.	Firm Transportation Obligation

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

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



	As of
	March 31,			December 31,
	2015			2014
Balance at beginning of period	$	14,790		$	15,993
Accretion	212			1,301
Cash payments, net	(523		)	(2,504		)
Balance at end of period	$	14,479		$	14,790

The accretion of the obligation, net of any recoveries from the periodic sale of our contractual capacity, is charged as an offset to Other revenue. As of March 31, 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 $11.7 million is classified as noncurrent and is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets.


10.	Additional Balance Sheet Detail

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



	As of
	March 31,		December 31,
	2015		2014
Other current assets:
Tubular inventory and well materials	$	5,323	$	5,802
Prepaid expenses	4,267		4,215
Other	97		97
	$	9,687	$	10,114
Other assets:
Assets of supplemental employee retirement plan (“SERP”)	4,216		4,123
Other	95		95
	$	4,311	$	4,218
Accounts payable and accrued liabilities:
Trade accounts payable	$	121,891	$	174,496
Drilling and other lease operating costs	47,131		68,842
Royalties	25,971		27,883
Compensation – related	4,313		9,197
Interest	37,630		15,555
Preferred stock dividends	6,067		6,067
Other	2,063		10,187
	$	245,066	$	312,227
Other liabilities:
Deferred gains on sale of assets	$	90,463	$	90,569
Firm transportation obligation	11,723		12,042
Asset retirement obligations (“AROs”)	6,049		5,889
Defined benefit pension obligations	1,565		1,753
Postretirement health care benefit obligations	914		890
Compensation – related	7,612		7,631
Deferred compensation – SERP obligations and other	4,270		4,183
Other	928		929
	$	123,524	$	123,886


11.	Fair Value Measurements

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

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of March 31, 2015, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

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



	As of
	March 31, 2015				December 31, 2014
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2019	$	271,500	$	300,000	$	234,000	$	300,000
Senior Notes due 2020	720,750		775,000		620,000		775,000
	$	992,250	$	1,075,000	$	854,000	$	1,075,000

Recurring Fair Value Measurements

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



	As of March 31, 2015
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Commodity derivative assets – current	$	118,409		$	—		$	118,409	$	—
Commodity derivative assets – noncurrent	31,844			—			31,844		—
Assets of SERP	4,216			4,216			—		—
Liabilities:
Deferred compensation – SERP obligations	(4,269		)	(4,269		)	—		—



	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 three months ended March 31, 2015 and 2014.

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

•

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


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


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

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements utilized in the preparation of our Condensed Consolidated Financial Statements are those attributable to the recognition and measurement of net assets acquired, the recognition and measurement of asset impairments and the initial determination of AROs. The factors used to determine fair value for purposes

of recognizing and measuring net assets acquired and asset impairments include, but are not limited to, estimates of proved and probable reserves, future commodity prices, indicative sales prices for properties, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties. Because these significant fair value inputs are typically not observable, we have categorized the amounts as level 3 inputs.

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


12.	Commitments and Contingencies

Drilling and Completion Commitments

As of March 31, 2015, we had contractual commitments for three drilling rigs with terms expiring in July 2015, September 2015 and February 2016, respectively. The minimum commitment under these agreements is $14.6 million for the remaining three quarters 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 three quarters of 2015 under this agreement is $4.8 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 March 31, 2015, the penalty amount would have been $16.2 million had we terminated our agreements on that date.

Firm Transportation Commitments

We have entered into contracts that provide 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 $1.5 million for the the remaining three quarters of 2015 and approximately $1.1 million per year through 2028. We may sell excess capacity to third parties at our discretion.

Gathering and Intermediate Transportation Commitments

We have entered into a long-term agreement that provides 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 $3.2 million for the remaining three quarters of 2015 and $5.0 million in 2016.

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

Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remained outstanding as of March 31, 2015. In March 2015, we established an additional $0.3 million reserve for litigation attributable to certain other properties that we previously sold. As of March 31, 2015, we also had AROs of approximately $6.0 million attributable to the plugging of abandoned wells.


13.	Shareholders’ Equity

The following tables summarize the components of our shareholders’ equity and the changes therein as of and for the three months ended March 31, 2015 and 2014:



	As of												As of
	December 31,						Dividends			All Other			March 31,
	2014			Net Loss			Declared ¹			Changes ²			2015
Preferred stock	$	4,044		$	—		$	—		$	—		$	4,044
Common stock	529			—			—			—			529
Paid-in capital	1,206,305			—			—			989			1,207,294
Accumulated deficit	(535,176		)	(57,165		)	(6,067		)	—			(598,408		)
Deferred compensation obligation	3,211			—			—			56			3,267
Accumulated other comprehensive income ³	249			—			—			(11		)	238
Treasury stock	(3,345		)	—			—			(55		)	(3,400		)
	$	675,817		$	(57,165	)	$	(6,067	)	$	979		$	613,564

	As of												As of
	December 31,						Dividends			All Other			March 31,
	2013			Net Income			Declared ¹			Changes ²			2014
Preferred stock	$	1,150		$	—		$	—		$	(2	)	$	1,148
Common stock	466			—			—			2			468
Paid-in capital	891,351			—			—			1,911			893,262
Accumulated deficit	(104,180		)	19,225			(1,722		)	—			(86,677		)
Deferred compensation obligation	2,792			—			—			105			2,897
Accumulated other comprehensive income ³	267			—			—			25			292
Treasury stock	(3,042		)	—			—			(105		)	(3,147		)
	$	788,804		$	19,225		$	(1,722	)	$	1,936		$	808,243

_______________________

¹ Includes dividends of $150.00 per share on our 6% Series A Convertible Perpetual Preferred Stock (the “Series A Preferred Stock”) and $150.00 per share on our 6% Series B Convertible Perpetual Preferred Stock (the “Series B Preferred Stock”).

² Includes equity-classified share-based compensation of $990 and $825 for the three months ended March 31, 2015 and 2014.

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 three months ended March 31, 2015 and 2014 represent reclassifications from AOCI to net periodic benefit expense, a component of General and administrative expenses, of $(17) and $38 and are presented above net of taxes of $(6) and $13.


14.	Share-Based Compensation

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

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

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



	Three Months Ended
	March 31,
	2015		2014
Equity-classified awards:
Stock option awards	$	393	$	461
Common, deferred and restricted stock and stock unit awards	597		364
	990		825
Liability-classified awards	379		5,945
	$	1,369	$	6,770

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


15.	Interest Expense

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



	Three Months Ended
	March 31,
	2015			2014
Interest on borrowings and related fees	$	22,808		$	23,140
Amortization of debt issuance costs	1,104			1,012
Capitalized interest	(1,899		)	(1,618		)
	$	22,013		$	22,534


16.	Earnings per Share

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



	Three Months Ended
	March 31,
	2015			2014
Net income (loss)	$	(57,165	)	$	19,225
Less: Preferred stock dividends	(6,067		)	(1,722		)
Net income (loss) attributable to common shareholders – basic	$	(63,232	)	$	17,503
Add: Preferred stock dividends ¹	—			1,722
Net income (loss) attributable to common shareholders – diluted	$	(63,232	)	$	19,225

Weighted-average shares – basic	71,820			65,611
Effect of dilutive securities ²	—			20,133
Weighted-average shares – diluted	71,820			85,744

_______________________

1 Preferred stock dividends were excluded from diluted earnings per share for the three months ended March 31, 2015, as the assumed conversion of the outstanding preferred stock would have been anti-dilutive.

² For the three months ended March 31, 2015, approximately 31.3 million potentially dilutive securities, including the Series A Preferred Stock and Series B Preferred Stock, stock options and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:


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


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


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


•	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;


•	drilling and operating risks;


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


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


•	leasehold terms expiring before production can be established;


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


•	the timing of receipt of necessary regulatory permits;


•	the effect of commodity and financial derivative arrangements;


•	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;


•	physical, electronic and cybersecurity breaches;


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


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

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


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

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

Overview and Executive Summary

We are an independent oil and gas company engaged in the exploration, development and production of oil, NGLs and natural gas in various onshore regions of the United States. Our current operations consist primarily of drilling unconventional horizontal development wells in the Eagle Ford Shale in South Texas. We also have operations in the Granite Wash in Oklahoma and the Haynesville Shale and Cotton Valley in East Texas. As of December 31, 2014, we had proved oil and gas reserves of approximately 115 million barrels of oil equivalent, or MMBOE.

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



	Three Months Ended
	March 31,
	2015			2014
Total production (MBOE)	2,225			1,902
Average daily production (BOEPD)	24,721			21,133
Crude oil and NGL production (MBbl)	1,734			1,303
Crude oil and NGL production as a percent of total	78		%	69		%
Product revenues, as reported	$	73,135		$	133,152
Product revenues, as adjusted for derivatives	$	110,627		$	130,095
Crude oil and NGL revenues as a percent of total, as reported	88		%	86		%
Realized prices:
Crude oil ($/Bbl)	$	44.26		$	98.12
NGL ($/Bbl)	$	13.60		$	41.27
Natural gas ($/Mcf)	$	2.91		$	5.07
Aggregate ($/BOE)	$	32.87		$	70.01
Operating costs ($/BOE):
Lease operating	$	5.20		$	5.32
Gathering, processing and transportation	3.37			1.71
Production and ad valorem taxes ($/BOE)	2.11			3.84
General and administrative ($/BOE) ¹	4.76			5.21
Total operating costs ($/BOE)	$	15.44		$	16.08
Depreciation, depletion and amortization ($/BOE)	$	40.79		$	37.95
Cash provided by operating activities	$	45,552		$	66,560
Cash paid for capital expenditures	$	168,994		$	159,804
Cash and cash equivalents at end of period	$	3,859		$	9,554
Debt outstanding at end of period	$	1,237,000		$	1,265,000
Credit available under revolving credit facility at end of period ²	$	286,196		$	208,346
Net development wells drilled and completed	14.1			13.8

_______________________

¹ Excludes equity-classified share-based compensation, which is a non-cash expense, of $0.44 and $0.43 for the three months ended March 31, 2015 and 2014 and liability-classified share-based compensation of $0.17 and $3.13 for the three months ended March 31, 2015 and 2014.

² As reduced by outstanding borrowings and letters of credit.

In the three months ended March 31, 2015, our crude oil and NGL production increased to 78 percent from 69 percent of our total production compared to the three month period ended March 31, 2014. Our growth in crude oil and NGL production has been focused exclusively in the Eagle Ford in South Texas. Since our initial acquisition in this region in 2010 and through May 8, 2015, we have developed or acquired a total of 309 gross (194.2 net) wells of which a substantial majority are operated by us. During this period, we have accumulated approximately 103,000 net acres in the Eagle Ford. We are currently operating a total of three drilling rigs, all in the Eagle Ford. Our capital program, which is substantially dedicated to this play, is being financed with a combination of cash from operating activities 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 months ended March 31, 2015 and 2014.

Key Developments

The following general business developments and corporate actions had or will have a significant impact on the financial reporting and disclosure of our results of operations, financial position and cash flows: (i) depressed commodity prices and our hedging program, (ii) future development and capital spending plans in the Eagle Ford and (iii) an amendment to the Revolver decreasing the commitment and borrowing base and modifying our financial covenants, among other things.

Depressed Commodity Prices and Our Hedging Program

Commodity prices remained depressed during the first quarter of 2015. While the economic circumstances in the first quarter of 2015 did not provide desirable opportunities to add additional hedges to our commodity derivative portfolio, our existing portfolio operated as designed and provided us with substantial cash inflows to support our liquidity in the current commodity price environment. Our crude oil derivatives provided cash settlements of $36.8 million during the quarter ended March 31, 2015. We have hedged 13,000 barrels of oil per day, or BOPD, during the second quarter of 2015, or approximately 85 to 90 percent of our expected crude oil production, at a weighted-average floor/swap price of $90.48 per barrel and we have hedged 11,000 BOPD, or approximately 70 to 80 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 short puts is 6,000 barrels per day for the second quarter of 2015, and 5,000 barrels per day for the second half of 2015. Our natural gas hedges expired at the end of the quarter and we expect to remain unhedged with respect to natural gas production for the foreseeable future. During the quarter ended March 31, 2015, our natural gas derivatives provided cash settlements of $0.7 million.

Future Development and Capital Spending Plans in the Eagle Ford

During the three months ended March 31, 2015, we completed and turned in line 27 gross (14.1 net) wells in the Eagle Ford. Our Eagle Ford production was 21,390 barrels of oil equivalent per day, or BOEPD, during the three months ended March 31, 2015 with oil comprising 14,523 BOPD, or 68 percent, and NGLs and natural gas comprising approximately 17 percent and 15 percent, respectively, compared to 17,459 BOEPD, 12,676 BOPD, or 73 percent of which was crude oil, 14 percent was NGLs and 13 percent was natural gas for the three months ended December 31, 2014.

Our well costs declined by approximately 25% for wells spud in February and March of 2015 as compared to wells spud in October and November of 2014. The cost decline is attributable to lower completion costs due primarily to ongoing optimization of completion design and improved stimulation pricing and, to a lesser extent, lower drilling costs. We expect to see additional decreases in drilling costs for the balance of the year as our cost reduction initiatives continue.

We anticipate total capital expenditures in 2015 of up to approximately $370 million with a focus on the Upper Eagle Ford. Our active Upper Eagle Ford drilling program completed and turned in line 11 gross well since the end of 2014. Since March 2014, 23 wells have been brought on line with an initial potential rate of 1,223 BOEPD and a 30-day average rate for 21 applicable wells of 942 BOEPD. Our plans anticipate a decrease in the rig count in 2015 as we expect certain of our partners to elect non-consent due to their individual capital constraints. Accordingly, we will likely incur incremental rig termination costs. Please read “Financial Condition – Capital Resources.”

Amendment to the Revolver

In May 2015, the Revolver was amended to decrease the 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 while limiting certain restricted payments and required an additional leverage covenant with respect to outstanding borrowings and letters of credit under the Revolver. Please read “Financial Condition – Capitalization: Covenant Compliance.”

Results of Operations

Production

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



	Total Production				Average Daily Production
Crude oil	Three Months Ended				Three Months Ended
	March 31,		2015 vs.		March 31,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBbl)				(Bbl per day)
Texas
South Texas	1,307	1,036	271		14,523	11,512	3,011
East Texas	11	13	(2	)	123	142	(19	)
Mid-Continent	19	24	(5	)	209	272	(63	)
Other	—	3	(3	)	—	29	(29	)
	1,337	1,076	261		14,855	11,955	2,900
% Change							24	%

NGLs	Three Months Ended				Three Months Ended
	March 31,		2015 vs.		March 31,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBbl)				(Bbl per day)
Texas
South Texas	333	151	182		3,705	1,682	2,023
East Texas	28	24	4		309	271	38
Mid-Continent	36	51	(15	)	395	570	(175	)
Other	—	—	—		—	—	—
	397	227	171		4,409	2,523	1,886
% Change							75	%

Natural gas	Three Months Ended				Three Months Ended
	March 31,		2015 vs.		March 31,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MMcf)				(MMcf per day)
Texas
South Texas	1,707	846	861		19	9	10
East Texas	806	1,070	(264	)	9	12	(3	)
Mid-Continent	399	588	(189	)	4	7	(3	)
Other	34	1,089	(1,055	)	—	12	(12	)
	2,947	3,593	(647	)	33	40	(8	)
% Change							(20	)%

Combined total	Three Months Ended				Three Months Ended
	March 31,		2015 vs.		March 31,		2015 vs.
	2015	2014	2014		2015	2014	2014
	(MBbl)				(Bbl per day)
Texas
South Texas	1,925	1,329	596		21,390	14,761	6,629
East Texas	173	215	(42	)	1,925	2,394	(469	)
Mid-Continent	122	174	(52	)	1,343	1,931	(588	)
Other ¹	6	184	(179	)	63	2,047	(1,984	)
	2,225	1,902	323		24,721	21,133	3,588
% Change							17	%

_______________________


¹	Comprised of our three active Marcellus Shale wells in Pennsylvania and, for the three months ended March 31, 2014, our divested Selma Chalk assets in Mississippi.

Total production increased during the three months ended March 31, 2015 compared to the corresponding period of 2014 due primarily to the 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 the three months ended March 31, 2015 was attributable to oil and NGLs, which represents an increase of approximately 33 percent over the prior year period. During the three months ended March 31, 2015, our Eagle Ford production represented approximately 87 percent of our total production compared to approximately 70 percent from this play during the corresponding period of 2014.

Product Revenues and Prices

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



Crude oil	Three Months Ended							Three Months Ended
	March 31,				2015 vs.			March 31,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Bbl)
Texas
South Texas	$	57,802	$	101,767	$	(43,965	)	$	44.22	$	98.23	$	(54.01	)
East Texas	502		1,253		(751		)	45.43		97.82		(52.39		)
Mid-Continent	864		2,308		(1,444		)	45.89		94.31		(48.42		)
Other	—		248		(248		)	—		94.91		(94.91		)
	$	59,168	$	105,576	$	(46,408	)	$	44.26	$	98.12	$	(53.86	)
% Change												(55		)%

NGLs	Three Months Ended							Three Months Ended
	March 31,				2015 vs.			March 31,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Bbl)
Texas
South Texas	$	4,135	$	4,815	$	(680	)	$	12.40	$	31.80	$	(19.40	)
East Texas	493		1,513		(1,020		)	17.70		62.00		(44.30		)
Mid-Continent	768		3,045		(2,277		)	21.62		59.39		(37.77		)
Other	—		—		—			—		—		—
	$	5,396	$	9,373	$	(3,977	)	$	13.60	$	41.27	$	(27.67	)
% Change												(67		)%

Natural gas	Three Months Ended							Three Months Ended
	March 31,				2015 vs.			March 31,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per Mcf)
Texas
South Texas	$	4,928	$	3,813	$	1,115		$	2.89	$	4.51	$	(1.62	)
East Texas	2,327		5,915		(3,588		)	2.89		5.53		(2.64		)
Mid-Continent	1,246		3,111		(1,865		)	3.12		5.29		(2.17		)
Other	70		5,364		(5,294		)	2.06		4.92		(2.86		)
	$	8,571	$	18,203	$	(9,632	)	$	2.91	$	5.07	$	(2.16	)
% Change												(43		)%

Combined total	Three Months Ended							Three Months Ended
	March 31,				2015 vs.			March 31,				2015 vs.
	2015		2014		2014			2015		2014		2014
								($ per BOE)
Texas
South Texas	$	66,865	$	110,395	$	(43,530	)	$	34.73	$	83.10	$	(48.37	)
East Texas	3,322		8,681		(5,359		)	19.17		40.29		(21.12		)
Mid-Continent	2,878		8,464		(5,586		)	23.82		48.71		(24.89		)
Other	70		5,612		(5,542		)	12.39		30.47		(18.08		)
	$	73,135	$	133,152	$	(60,017	)	$	32.87	$	70.01	$	(37.14	)
% Change												(53		)%

The following table provides an analysis of the change in our revenues for the three months ended March 31, 2015 compared to the corresponding period in the prior year:



	2015 vs. 2014 Revenue Variance Due to
	Volume			Price			Total
Crude oil	$	25,602		$	(72,010	)	$	(46,408	)
NGL	7,004			(10,981		)	(3,977		)
Natural gas	(3,276		)	(6,356		)	(9,632		)
	$	29,330		$	(89,347	)	$	(60,017	)

Effects of Derivatives

In the three months ended March 31, 2015 and 2014, we received $37.5 million and paid $3.1 million, respectively, in cash settlements of oil and gas derivatives. The following table reconciles crude oil and natural gas revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Three Months Ended
	March 31,					Favorable
	2015		2014			(Unfavorable)
Crude oil revenues as reported	$	59,168	$	105,576		$	(46,408	)
Derivative settlements, net	36,811		(2,278		)	39,089
	$	95,979	$	103,298		$	(7,319	)

Crude oil prices per Bbl, as reported	$	44.26	$	98.12		$	(53.86	)
Derivative settlements per Bbl	27.53		(2.12		)	29.66
	$	71.79	$	96.00		$	(24.20	)

Natural gas revenues as reported	$	8,571	$	18,203		$	(9,632	)
Derivative settlements, net	681		(779		)	1,460
	$	9,252	$	17,424		$	(8,172	)

Natural gas prices per Mcf, as reported	$	2.91	$	5.07		$	(2.16	)
Derivative settlements per Mcf	0.23		(0.22		)	0.45
	$	3.14	$	4.85		$	(1.71	)

Gain (Loss) on Sales of Property and Equipment

Gain (loss) on sales of property and equipment decreased in the 2015 period compared to the corresponding period in the prior year as a result of a $56.8 million gain recognized in connection with sale of our South Texas natural gas gathering and gas lift assets.

Other Revenues

Other revenues, which includes includes gathering, transportation, compression, water supply and disposal fees that we charge to other parties, net of marketing and related expenses and accretion of our unsused firm transportation obligation, increased $1.6 million to $1.5 million during the three months ended March 31, 2015 from the corresponding period in 2014 due primarily to income related to water supply and disposal which began in April 2014.

Lease Operating Expenses



	Three Months Ended
	March 31,				2015 vs.
	2015		2014		2014
					Favorable (unfavorable)
Lease operating	$	11,569	$	10,116	$	(1,453	)
Per unit of production ($/BOE)	$	5.20	$	5.32	$	0.12
% Change per unit of production					2		%

Lease operating expense increased on an absolute basis but decreased on a per-unit basis during the three months ended March 31, 2015 compared to the corresponding period of 2014 due primarily to higher production volume during the 2015 period. We incurred higher costs for compression and gas lift in the 2015 period due primarily to the higher production volume

as well as the utilization of compression services from the buyer of our former natural gas gathering and gas lift assets in South Texas, which began in February 2014. Those services were previously provided internally when we owned the underlying assets. We incurred higher workover and subsurface maintenance costs in both South and East Texas. All other costs, including chemical, water disposal, environmental compliance and labor costs in the South Texas region, increased on an absolute basis attributable primarily to the continued expansion of operations.

Gathering, Processing and Transportation



	Three Months Ended
	March 31,				2015 vs.
	2015		2014		2014
					Favorable (unfavorable)
Gathering, processing and transportation	$	7,498	$	3,249	$	(4,249	)
Per unit of production ($/BOE)	$	3.37	$	1.71	$	(1.66	)
% Change per unit of production					(97		)%

Gathering, processing and transportation charges increased during the three months ended March 31, 2015 compared to the corresponding period of 2014 due primarily to higher production volume and to gathering and common delivery point compression charges for natural gas and NGL production in the South Texas region as discussed above. 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 due to the sale of our Mississippi assets in July 2014.

Production and Ad Valorem Taxes



	Three Months Ended
	March 31,						2015 vs.
	2015			2014			2014
							Favorable (unfavorable)
Production and ad valorem taxes
Production/severance taxes	$	3,246		$	6,370		$	3,124
Ad valorem taxes	1,443			935			(508		)
	$	4,689		$	7,305		$	2,616
Per unit production ($/BOE)	$	2.11		$	3.84		$	1.73
% Change per unit of production							45		%
Production/severance tax rate as a percent of product revenue	4.4		%	4.8		%

Production taxes decreased during the three months ended March 31, 2015 due primarily to the substantial year-over-year decline in commodity prices. Ad valorem taxes increased primarily as a result of the expansion of our operations in the South Texas region.

General and Administrative

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



	Three Months Ended
	March 31,					2015 vs.
	2015			2014		2014
						Favorable (unfavorable)
Recurring general and administrative expenses	$	10,612		$	9,699	$	(913	)
Share-based compensation (liability-classified)	379			5,945		5,566
Share-based compensation (equity-classified)	990			825		(165		)
Significant non-recurring expenses:
Acquisition-related arbitration and other costs	—			207		207
Restructuring expenses	(11		)	12		23
Total general and administrative expenses	$	11,970		$	16,688	$	4,718
Per unit of production ($/BOE)	$	5.38		$	8.77	$	3.39
% Change per unit of production						39		%
Per unit of production excluding equity-classified and liability-classified share-based compensation expense ($/BOE)	$	4.76		$	5.21	$	0.45
Per unit of production excluding all share-based compensation and other non-recurring expenses identified above ($/BOE)	$	4.77		$	5.10	$	0.33

Our total general and administrative expenses decreased on both an absolute and per-unit basis during the three months ended March 31, 2015 compared to the corresponding period of 2014. Increases in recurring general and administrative expenses were attributable primarily to salary, wage and benefits related to the expansion of our workforce in the first half of 2014 consistent with our growth in the South Texas region. These costs were spread over an increasing production volume base which resulted in a lower per-unit cost. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, and represents mark-to-market charges associated with the increase in fair value of the outstanding PBRSU grants. While our common stock performance relative to a defined peer group was favorable, the relative performance was not as significant as that experienced in the three months ended March 31, 2014. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, increased during the three months ended March 31, 2015 due primarily to a change in the mix of grant-date vesting provisions for certain awards.

Exploration

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



	Three Months Ended
	March 31,					2015 vs.
	2015			2014		2014
						Favorable (unfavorable)
Unproved leasehold amortization	$	1,983		$	3,294	$	1,311
Drilling rig termination charges	3,625			—		(3,625		)
Geological and geophysical costs	287			4,500		4,213
Other, primarily delay rentals	(8		)	842		850
	$	5,887		$	8,636	$	2,749

Unproved leasehold amortization decreased during the three months ended March 31, 2015 due primarily to a declining leasehold asset base subject to amortization in the 2015 period as compared to the 2014 period. We incurred early termination charges of $3.6 million in the three months ended March 31, 2015 in connection with the release of a drilling rig in the South Texas region. Geological and geophysical and delay rental costs declined in the three months ended March 31, 2015 due to a significant decrease in our capital program and limited exploration activity in the 2015 period.

Depreciation, Depletion and Amortization (DD&A)

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



	Three Months Ended
	March 31,						2015 vs.
	2015			2014			2014
							Favorable (unfavorable)
DD&A expense	$	90,760		$	72,187		$	(18,573	)
DD&A rate ($/BOE)	$	40.79		$	37.95		$	(2.84	)

	Production			Rates			Total
DD&A variance due to:	$	(12,257	)	$	(6,316	)	$	(18,573	)

The effects of higher production volumes and higher depletion rates attributable to the higher-cost oil drilling program in the Eagle Ford were the primary factors attributable to the increase in DD&A.

Interest Expense

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



	Three Months Ended
	March 31,						2015 vs.
	2015			2014			2014
							Favorable (unfavorable)
Interest on borrowings and related fees	$	22,808		$	23,140		$	332
Amortization of debt issuance costs	1,104			1,012			(92		)
Capitalized interest	(1,899		)	(1,618		)	281
	$	22,013		$	22,534		$	521
Weighted-average debt outstanding	$	1,188,500		$	1,276,750
Weighted average interest rate	8.05		%	7.57		%

Interest expense decreased marginally during the three months ended March 31, 2015 compared to the corresponding period in 2014 due primarily to lower weighted-average Revolver borrowings outstanding during the 2015 period.

Derivatives

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



	Three Months Ended
	March 31,						2015 vs.
	2015			2014			2014
							Favorable (unfavorable)
Oil and gas derivatives settled	$	37,492		$	(3,057	)	$	40,549
Oil and gas derivatives gain (loss)	(14,625		)	(12,605		)	(2,020		)
	$	22,867		$	(15,662	)	$	38,529

We received cash settlements of $36.8 million for crude oil derivatives and $0.7 million for natural gas derivatives during the three months ended March 31, 2015 and paid settlements of $2.3 million for crude oil derivatives and $0.8 million for natural gas derivatives during the three months ended March 31, 2014.

Income Taxes



	Three Months Ended
	March 31,						2015 vs.
	2015			2014			2014
							Favorable (unfavorable)
Income tax (expense) benefit	$	(141	)	$	(14,264	)	$	14,123
Effective tax rate	0.2		%	42.6		%

Financial Condition

Liquidity

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

Our current business plan contemplates capital expenditures in excess of our projected cash from operating activities for 2015. Subject to the variability of commodity prices and production that impacts our cash from operating activities, anticipated timing of our capital projects and any unanticipated expenditures, we plan to fund our 2015 capital program with cash from operating activities and borrowings under the Revolver. We have no debt maturities until September 2017 when the Revolver matures. We believe that our cash from operating activities and borrowing capacity under the Revolver will be sufficient to meet our debt service, preferred stock dividend and working capital requirements and our anticipated capital expenditures.

Capital Resources

In 2015, we anticipate making capital expenditures of up to approximately $370 million. We expect to allocate substantially all of our capital expenditures to the Eagle Ford. This allocation includes approximately 95 percent for drilling and completions, three percent for leasehold acquisition and two percent for facilities and other projects. Our 2015 business plan assumes a drilling program utilizing three operated drilling rigs in the Eagle Ford through June with a reduction to two beginning in June 2015 as we anticipate certain of our partners to elect non-consent due to their individual capital constraints. Accordingly, we will likely incur rig termination costs of up to approximately $2 million. We continually review drilling and other 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 three months ended March 31, 2015, our commodity derivatives portfolio resulted in $36.8 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 13,000 BOPD during the second quarter of 2015, or approximately 85 to 90 percent of our expected crude oil production, at a weighted-average floor/swap price of $90.48 per barrel and we have hedged 11,000 BOPD, or approximately 70 to 80 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 4,000 barrels of daily crude oil production at weighted-average floor/swap prices of $88.12 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 short puts is 6,000 barrels per day for the second quarter of 2015, and 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 $425 million revolving commitment, a decrease of $25 million from the prior $450 million commitment, as a result of the May 2015 borrowing base re-determination. 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. Effective with the borrowing base re-determination in May 2015 and subsequent amendment, the borrowing base was reduced by $75 million to $425 million from $500 million. The next semi-annual redetermination is scheduled for November 2015. In addition, the Revolver was amended to increase the existing leverage ratio (total debt to EBITDAX, a non-GAAP measure) covenant for the remainder of

its term, limit the payment of cash dividends on our outstanding convertible preferred stock under certain circumstances and to require an additional leverage covenant with respect to outstanding borrowings and letters of credit under the Revolver. 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 March 31, 2015. As of March 31, 2015, our available borrowing capacity under the Revolver was $286.2 million (before giving effect to the reduced borrowing base). The available borrowing capacity would be reduced to $261.2 as of March 31, 2015 on a pro forma basis (giving effect to the reduced borrowing base).

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



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three months ended March 31, 2015	$	126,344	$	162,000	1.8707	%

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.

Capital Market Transactions. From time-to-time and under market conditions that we believe are favorable to us, we consider capital market transactions, including the offering of debt and equity securities. Historically, we have entered into such transactions to facilitate acquisitions and to pursue opportunities to adjust our total capitalization.

Cash Flows

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



	Three Months Ended
	March 31,
	2015			2014			Variance
Cash flows from operating activities
Operating cash flows, net	$	18,913		$	70,003		$	(51,090	)
Working capital changes (excluding restructuring costs paid), net	(6,649		)	264			(6,913		)
Commodity derivative settlements (paid) received, net:
Crude oil	36,811			(2,278		)	39,089
Natural gas	681			(779		)	1,460
Drilling rig termination charges paid	(3,625		)	—			(3,625		)
Restructuring and exit costs paid	(579		)	(650		)	71
Net cash provided by operating activities	45,552			66,560			(21,008		)
Cash flows from investing activities
Capital expenditures – property and equipment	(168,994		)	(159,804		)	(9,190		)
Proceeds from sales of assets, net	116			95,964			(95,848		)
Net cash used in investing activities	(168,878		)	(63,840		)	(105,038		)
Cash flows from financing activities
Proceeds (repayments) from revolving credit facility borrowings, net	127,000			(16,000		)	143,000
Dividends paid on preferred stock	(6,067		)	(1,725		)	(4,342		)
Other, net	—			1,085			(1,085		)
Net cash provided by financing activities	120,933			(16,640		)	137,573
Net decrease in cash and cash equivalents	$	(2,393	)	$	(13,920	)	$	11,527

Cash Flows From Operating Activities. Despite higher total production volume during the three months ended March 31, 2015 compared to the corresponding period in 2014, commodity prices declined substantially resulting in lower realized cash receipts from sales. Higher working capital changes were driven primarily by net payments in the 2015 period attributable to the eight rig capital program that was still in place at the end of 2014. In addition, the 2015 period includes charges paid to release one drilling rig in connection with the reduction to the scale of our 2015 capital program in response to declining commodity prices. This decrease was offset to some extent by cash settlements from our commodity derivatives portfolio which generated cash receipts during the 2015 period as compared to net payments during the 2014 period.

Cash Flows From Investing Activities. Cash paid for capital expenditures was higher during the three months ended March 31, 2015 compared to the corresponding period during 2014 due primarily to payments in 2015 for capital expenditure amounts accrued at the end of 2014, at which time we were operating eight drilling rigs and had multiple well completion

service providers under contract. 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.

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



	Three Months Ended
	March 31,
	2015		2014
Oil and gas:
Drilling and completion	$	134,140	$	135,455
Lease acquisitions and other land-related costs¹	8,804		36,878
Pipeline, gathering facilities and other equipment	2,868		4,410
Geological, geophysical (seismic) and delay rental costs	279		5,272
	146,091		182,015
Other – Corporate	384		378
Total capital program costs	$	146,475	$	182,393

______________________

¹ Includes site preparation and other pre-drilling costs.

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



	Three Months Ended
	March 31,
	2015			2014
Total capital program costs	$	146,475		$	182,393
Decrease (increase) in accrued capitalized costs	21,359			(18,629		)
Less:
Exploration costs charged to operations:
Geological, geophysical (seismic) and delay rental costs	(279		)	(5,272		)
Transfers from tubular inventory and well materials	(2,542		)	(409		)
Add:
Tubular inventory and well materials purchased in advance of drilling	2,082			103
Capitalized interest	1,899			1,618
Total cash paid for capital expenditures	$	168,994		$	159,804

Cash Flows From Financing Activities. Cash flows from financing activities for the three months ended March 31, 2015 included borrowings of $127 million under the Revolver used to fund a portion of our capital expenditures while the 2014 period included net repayments of $16 million which were sourced primarily by proceeds from the sale of our South Texas natural gas gathering and gas lift assets. We paid total dividends of $6.1 million for the 6% Series A Convertible Perpetual Preferred Stock, or Series A Preferred Stock and the 6% Series B Convertible Perpetual Preferred Stock, or Series B Preferred Stock during the three months ended March 31, 2015. Dividends of $1.7 million were paid during the comparable period in 2014 on the Series A Preferred Stock. We also received proceeds of $1.1 million during the 2014 period from the exercise of stock options.

Capitalization

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



	March 31,			December 31,
	2015			2014
Revolving credit facility	$	162,000		$	35,000
Senior notes due 2019	300,000			300,000
Senior notes due 2020	775,000			775,000
Total debt	1,237,000			1,110,000
Shareholders' equity ¹	613,564			675,817
	$	1,850,564		$	1,785,817
Debt as a % of total capitalization	67		%	62		%

_____________________

¹ Includes 7,945 shares of the Series A Preferred Stock and 32,500 shares of the Series B Preferred Stock as of March 31, 2015 and December 31, 2013. Both series of preferred stock have a liquidation preference of $10,000 per share representing a total of $404 million as of March 31, 2015 and December 31, 2014.

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 March 31, 2015, the actual interest rate applicable to the Revolver was 1.9375%, which is derived from an Adjusted LIBOR rate of 0.1875% plus an applicable margin of 1.75%. Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of March 31, 2015, commitment fees were being charged at a rate of 0.375%.

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

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

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

Series A 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. Cash payment of dividends, however, 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 convert shares of the Series A and Series B Preferred Stock upon the occurrence of certain specified fundamental changes, we

may be obligated to deliver an additional number of shares above the applicable conversion rate to compensate the holder for lost option value.

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

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

The Revolver, as amended in May 2015, requires us to maintain certain financial covenants as follows:

•

Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.0 to 1.0 for periods through March 31, 2015, 4.75 to 1.0 for periods through March 31, 2016, 5.25 to 1.0 for periods through June 30, 2016, 5.50 to 1.0 for periods through December 31, 2016, 4.50 to 1.0 for periods through March 31, 2017 and 4.0 to 1.0 through maturity in September 2017. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.


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


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

In addition, in connection with the amendment in May 2015, we are precluded from the payment of cash dividends on our outstanding convertible preferred stock if the total debt to EBITDAX ratio exceeds 5.0 to 1.0.

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

As of March 31, 2015 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants. The following table summarizes the actual results of our financial covenant compliance under the Revolver as of and for the period ended March 31, 2015:



	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.00 to 1	3.5 to 1
Current ratio	> 1.00 to 1	1.8 to 1
Interest coverage	> 2.25 to 1	3.2 to 1

Critical Accounting Estimates

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

New Accounting Standards

Effective January 2015, we adopted the provisions of ASU No. 2015–03, Simplifying the Presentation of Debt Issuance Costs, or ASU 2015–03, on a retrospective basis. ASU 2015–03 requires that debt issuance costs be presented as a direct reduction to the face amount of the underlying debt instruments to which they are attributable. Accordingly, we have presented the debt issuance costs, net of amortization, associated with our outstanding senior notes and revolving credit facility (the

“Revolver”), 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.

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

Item 3 Quantitative and Qualitative Disclosures About Market Risk

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

Interest Rate Risk

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 March 31, 2015, we had borrowings of $162 million under the Revolver at an interest rate of 1.9375%. Assuming a constant borrowing level of $162 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) of approximately $1.6 million on an annual basis.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars 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 March 31, 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 five of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions.

During the three months ended March 31, 2015, we reported net commodity derivative gains of $22.9 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in crude oil, NGL and natural gas prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

The following table sets forth our commodity derivative positions as of March 31, 2015:



		Average
		Volume Per	Weighted Average Price				Fair Value
	Instrument	Day	Floor/Swap		Ceiling		Asset		Liability
Crude Oil:		(barrels)	($/barrel)
Second quarter 2015	Collars	4,000	$	87.50	$	94.66	$	10,045	$	—
Third quarter 2015	Collars	3,000	$	86.67	$	94.73	6,063		—
Fourth quarter 2015	Collars	3,000	$	86.67	$	94.73	5,738		—
Second quarter 2015	Swaps	9,000	$	91.81			27,053		—
Third quarter 2015	Swaps	8,000	$	91.06			23,139		—
Fourth quarter 2015	Swaps	8,000	$	91.06			21,918		—
First quarter 2016	Swaps	4,000	$	88.12			11,392		—
First quarter 2016	Swaps	4,000	$	88.12			10,933		—
First quarter 2016	Swaps	4,000	$	88.12			10,649		—
First quarter 2016	Swaps	4,000	$	88.12			10,262		—

Settlements to be received in subsequent period							13,061		—

_______________________

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This illustration assumes that crude oil prices, natural gas prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.



	Change of $10.00 per Bbl of Crude Oil or $1.00 per MMBtu of Natural Gas ($ in millions)
	Increase			Decrease
Effect on the fair value of crude oil derivatives	$	(34.9	)	$	32.7

Effect on the remainder of 2015 operating income, excluding crude oil derivatives	$	33.3		$	(33.3	)
Effect on the remainder of 2015 operating income, excluding natural gas derivatives	$	7.9		$	(7.9	)

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 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 March 31, 2015, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

During the three months ended March 31, 2015, no changes were made in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION


Item 1	Legal Proceedings

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


Item 6	Exhibits



(10.1)	Penn Virginia Corporation Amended and Restated Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 17, 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

SIGNATURES

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



	PENN VIRGINIA CORPORATION

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

May 11, 2015	By:	/s/ JOAN C. SONNEN
		Joan C. Sonnen
		Vice President, Chief Accounting Officer and Controller
		(Principal Accounting Officer)