BAYTEX ENERGY USA, INC. - Quarter Report: 2012 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-Q

____________________________________________________________________________

(Mark One)



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

For the quarterly period ended June 30, 2012



¨	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 No.)

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. x Yes ¨ 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 x No ¨

Indicate by a 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.



Large accelerated filer	x		Accelerated filer	¨

Non-accelerated filer	¨	(Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of July 27, 2012, 45,877,121 shares of common stock of the registrant were outstanding.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2012

Table of Contents



Item		Page
	Part I - Financial Information

1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended June 30, 2012 and 2011	1
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended June 30, 2012 and 2011	2
	Condensed Consolidated Balance Sheets as of June 30, 2012 and December 31, 2011	3
	Condensed Consolidated Statements of Cash Flows for the Periods Ended June 30, 2012 and 2011	4
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	5
	2. Basis of Presentation	5
	3. Acquisitions and Divestitures	5
	4. Accounts Receivable and Major Customers	6
	5. Derivative Instruments	6
	6. Property and Equipment	9
	7. Long-Term Debt	9
	8. Additional Balance Sheet Detail	11
	9. Fair Value Measurements	12
	10. Commitments and Contingencies	13
	11. Shareholders’ Equity	14
	12. Share-Based Compensation	14
	13. Restructuring Activities	15
	14. Impairments	15
	15. Interest Expense	16
	16. Earnings per Share	16
Forward-Looking Statements		17
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:	18
	Overview of Business	18
	Key Developments	19
	Results of Operations	20
	Liquidity and Capital Resources	35
	Environmental Matters	39
	Critical Accounting Estimates	40
	New Accounting Standards	40
3.	Quantitative and Qualitative Disclosures About Market Risk	41
4.	Controls and Procedures	43
	Part II - Other Information
6.	Exhibits	44
Signatures		45

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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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Revenues
Natural gas	$	10,303		$	38,300		$	25,189		$	79,489
Crude oil	58,382			21,548			117,105			38,131
Natural gas liquids (NGLs)	7,556			13,161			16,627			23,082
Gain (loss) on sales of property and equipment	78			(28		)	834			452
Other	526			637			1,501			1,047
Total revenues	76,845			73,618			161,256			142,201
Operating expenses
Lease operating	9,264			10,787			18,407			21,064
Gathering, processing and transportation	4,391			4,281			8,545			8,309
Production and ad valorem taxes	(254		)	2,834			3,326			7,898
General and administrative	11,747			12,954			23,888			26,306
Exploration	9,384			19,368			17,382			48,916
Depreciation, depletion and amortization	51,740			33,036			102,557			67,879
Impairments	28,616			71,071			28,616			71,071
Total operating expenses	114,888			154,331			202,721			251,443
Operating loss	(38,043		)	(80,713		)	(41,465		)	(109,242		)
Other income (expense)
Interest expense	(15,084		)	(14,143		)	(29,858		)	(27,627		)
Loss on extinguishment of debt	—			(24,238		)	—			(24,238		)
Derivatives	43,826			7,001			43,521			8,329
Other	28			129			29			273
Loss before income taxes	(9,273		)	(111,964		)	(27,773		)	(152,505		)
Income tax benefit	3,635			40,046			10,236			54,247
Net loss	$	(5,638	)	$	(71,918	)	$	(17,537	)	$	(98,258	)
Loss per share:
Basic	$	(0.12	)	$	(1.57	)	$	(0.38	)	$	(2.15	)
Diluted	$	(0.12	)	$	(1.57	)	$	(0.38	)	$	(2.15	)
Weighted average shares outstanding, basic	46,030			45,768			45,988			45,724
Weighted average shares outstanding, diluted	46,030			45,768			45,988			45,724

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(5,638	)	$	(71,918	)	$	(17,537	)	$	(98,258	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $13 and $26 in 2012 and $18 and $36 in 2011	23			34			46			68
	23			34			46			68
Comprehensive loss	$	(5,615	)	$	(71,884	)	$	(17,491	)	$	(98,190	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)



	As of
	June 30, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents	$	11,532		$	7,512
Accounts receivable, net of allowance for doubtful accounts	55,751			72,432
Derivative assets	26,763			18,987
Income taxes receivable	31,154			31,465
Other current assets	6,850			14,950
Total current assets	132,050			145,346
Property and equipment, net (successful efforts method)	1,811,553			1,777,575
Derivative assets	12,664			—
Other assets	20,805			20,132
Total assets	$	1,977,072		$	1,943,053
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	84,222		$	94,504
Derivative liabilities	617			3,549
Deferred income taxes	3,807			3,808
Current portion of long-term debt	4,837			4,746
Total current liabilities	93,483			106,607
Other liabilities	16,575			15,887
Derivative liabilities	1,651			6,850
Deferred income taxes	264,631			274,839
Long-term debt	774,144			692,561
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; none issued	—			—
Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued of 45,877,121 and 45,714,191 as of June 30, 2012 and December 31, 2011, respectively	271			270
Paid-in capital	693,078			690,131
Retained earnings	134,529			157,242
Deferred compensation obligation	3,032			3,620
Accumulated other comprehensive loss	(1,038		)	(1,084		)
Treasury stock – 202,875 and 223,886 shares of common stock, at cost, as of June 30, 2012 and December 31, 2011, respectively	(3,284		)	(3,870		)
Total shareholders’ equity	826,588			846,309
Total liabilities and shareholders’ equity	$	1,977,072		$	1,943,053

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)



	Six Months Ended June 30,
	2012			2011
Cash flows from operating activities
Net loss	$	(17,537	)	$	(98,258	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Non-cash portion of loss on extinguishment of debt	—			21,822
Depreciation, depletion and amortization	102,557			67,879
Impairments	28,616			71,071
Derivative contracts:
Net gains	(43,521		)	(8,329		)
Cash settlements	14,951			11,775
Deferred income tax benefit	(10,236		)	(54,247		)
Gain on sales of property and equipment, net	(834		)	(452		)
Non-cash exploration expense	16,455			41,081
Non-cash interest expense	2,050			4,750
Share-based compensation (equity-classified)	2,951			3,809
Other, net	203			265
Changes in operating assets and liabilities, net	20,070			2,593
Net cash provided by operating activities	115,725			63,759
Cash flows from investing activities
Capital expenditures - property and equipment	(188,236		)	(211,081		)
Proceeds from sales of property and equipment, net	527			696
Other, net	180			100
Net cash used in investing activities	(187,529		)	(210,285		)
Cash flows from financing activities
Dividends paid	(5,176		)	(5,156		)
Proceeds from revolving credit facility borrowings	84,000			—
Repayment of revolving credit facility borrowings	(3,000		)	—
Proceeds from the issuance of senior notes	—			300,000
Repurchase of Convertible Notes	—			(232,963		)
Debt issuance costs paid	—			(6,559		)
Other, net	—			974
Net cash provided by financing activities	75,824			56,296
Net increase (decrease) in cash and cash equivalents	4,020			(90,230		)
Cash and cash equivalents - beginning of period	7,512			120,911
Cash and cash equivalents - end of period	$	11,532		$	30,681
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	26,656		$	19,705
Income taxes (net of refunds received)	$	(311	)	$	(96	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended June 30, 2012

(in thousands, except per share amounts)


1.	Organization

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in various domestic onshore regions including Texas, Appalachia, the Mid-Continent and Mississippi.


2.	Basis of Presentation

Our Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated. Our Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America. 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, 2011. Operating results for the six months ended June 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Certain amounts for the 2011 period have been reclassified to conform to the current year presentation.

During the quarter ended June 30, 2012, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Condensed Consolidated Financial Statements and Notes.

Management has evaluated all activities of the Company through the date upon which the Condensed Consolidated Financial Statements were issued and concluded that, except for the sale of substantially all of our assets in the Appalachian region on July 31, 2012 (see Note 3), no subsequent events have occurred that would require recognition in the Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.


3.	Acquisitions and Divestitures

Property Acquisitions

Eagle Ford Property Acquisitions

In December 2011, we entered into an agreement with an industry partner to jointly explore a 13,500 acre area of mutual interest ("AMI") in Lavaca County, Texas. Under the terms of the agreement, we must commence drilling on six wells by September 1, 2012 to earn our entire interest in the acreage and must carry our partner on its working interest share of the costs of the first three wells. We drilled four (3.8 net) successful exploratory wells on the acreage in the six months ended June 30, 2012. Depending upon the future participation elections made by our partners, our ultimate working interest in wells drilled in the AMI is expected to be at least 57%.

Divestitures

Oil and Gas Properties

On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and customary purchase and sale adjustments. The transaction had an effective date of January 1, 2012. The properties sold included vertical and horizontal coalbed methane and conventional properties as well as royalty interests. The properties had net production of approximately 20 million cubic feet of natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. Estimated proved reserves associated with the properties, as determined by our third party reserve engineers as of December 31, 2011, were approximately 106 billion cubic feet of natural gas equivalent, of which 96 percent were proved developed and 100 percent were natural gas. Also included in the group of assets sold was a gathering system. During the quarter ended June 30, 2012, we recognized an impairment of $28.6 million with

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

respect to these assets.


4.	Accounts Receivable and Major Customers

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



	June 30, 2012			December 31, 2011
Customers	$	35,603		$	49,763
Joint interest partners	18,516			22,755
Other	2,895			1,695
	57,014			74,213
Less: Allowance for doubtful accounts	(1,263		)	(1,781		)
	$	55,751		$	72,432

For the six months ended June 30, 2012 and 2011, six customers accounted for $79.5 million and $95.4 million, or approximately 50% and 68%, of our total consolidated product revenues. As of June 30, 2012 and December 31, 2011, $14.4 million and $29.8 million, or approximately 26% and 41%, of our consolidated accounts receivable, including joint interest billings, related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by these customers.


5.	Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to natural gas and crude oil price volatility as well as the volatility in interest rates attributable to our debt instruments. We are not engaged in the trading of derivative instruments for speculative purposes. The derivative instruments are placed with financial institutions that we believe are acceptable credit risks. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We utilize collars, swaps, and swaptions 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. As of June 30, 2012, we have hedged our future crude oil production through 2014 to the greatest extent permitted by our revolving credit agreement (the "Revolver") and our internal policies.

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.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table sets forth our commodity derivative positions as of June 30, 2012:



		Average Volume Per Day	Weighted Average Price				Fair Value
	Instrument	Average Volume Per Day	Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)	($/MMBtu)
Third quarter 2012	Swaps	20,000	$	5.31			$	4,594	$	—
Fourth quarter 2012	Swaps	10,000	$	5.10			1,824		—
Crude Oil:		(barrels)	($/barrel)
Third quarter 2012	Collars	1,000	$	90.00	$	97.00	519		—
Fourth quarter 2012	Collars	1,000	$	90.00	$	97.00	512		—
First quarter 2013	Collars	1,000	$	90.00	$	100.00	518		—
Second quarter 2013	Collars	1,000	$	90.00	$	100.00	491		—
Third quarter 2013	Collars	1,000	$	90.00	$	100.00	503		—
Fourth quarter 2013	Collars	1,000	$	90.00	$	100.00	521		—
Third quarter 2012	Swaps	3,000	$	104.40			5,204		—
Fourth quarter 2012	Swaps	3,000	$	104.40			4,817		—
First quarter 2013	Swaps	2,250	$	103.51			3,108		—
Second quarter 2013	Swaps	2,250	$	103.51			3,004		—
Third quarter 2013	Swaps	1,500	$	102.77			1,916		—
Fourth quarter 2013	Swaps	1,500	$	102.77			1,940		—
First quarter 2014	Swaps	2,000	$	100.44			2,166		—
Second quarter 2014	Swaps	2,000	$	100.44			2,232		—
Third quarter 2014	Swaps	1,500	$	100.20			1,687		—
Fourth quarter 2014	Swaps	1,500	$	100.20			1,699		—
First quarter 2013	Swaption	1,100	$	100.00			—		290
Second quarter 2013	Swaption	1,000	$	100.00			—		241
Third quarter 2013	Swaption	900	$	100.00			—		180
Fourth quarter 2013	Swaption	750	$	100.00			—		117
First quarter 2014	Swaption	812	$	100.00			—		338
Second quarter 2014	Swaption	812	$	100.00			—		338
Third quarter 2014	Swaption	812	$	100.00			—		339
Fourth quarter 2014	Swaption	812	$	100.00			—		339
Settlements to be received in subsequent period							2,086		—

Interest Rate Swaps

In February 2012, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (“2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds.

During the six months ended June 30, 2011, we had an interest rate swap agreement in effect that established variable rates on approximately one-third of the face amount of the outstanding obligation under our 10.375% Senior Notes due 2016 (“2016 Senior Notes"). In August 2011, we terminated this agreement and received $2.9 million in cash proceeds.

As of June 30, 2012, we had no interest rate derivative instruments outstanding.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Financial Statement Impact of Derivatives

The impact of our derivative 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 June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Impact by contract type:
Commodity contracts	$	41,821	$	5,997	$	42,115	$	7,305
Interest rate contracts	2,005		1,004		1,406		1,024
	$	43,826	$	7,001	$	43,521	$	8,329
Realized and unrealized impact:
Cash received for:
Commodity contract settlements	$	5,564	$	4,133	$	13,545	$	10,877
Interest rate contract settlements	1,406		898		1,406		898
	6,970		5,031		14,951		11,775
Unrealized gains (losses) attributable to:
Commodity contracts	36,257		1,864		28,570		(3,572		)
Interest rate contracts	599		106		—		126
	36,856		1,970		28,570		(3,446		)
	$	43,826	$	7,001	$	43,521	$	8,329

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

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



		Fair Values as of
		June 30, 2012				December 31, 2011
Type	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	26,763	$	617	$	18,987	$	3,549
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		26,763		617		18,987		3,549
Commodity contracts	Derivative assets/liabilities - noncurrent	12,664		1,651		—		6,850
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		12,664		1,651		—		6,850
		$	39,427	$	2,268	$	18,987	$	10,399

As of June 30, 2012, we reported a commodity derivative asset of $39.4 million. The contracts associated with this position are with six counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


6.	Property and Equipment

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



	June 30, 2012			December 31, 2011
Oil and gas properties:
Proved	$	2,380,954		$	2,239,186
Unproved	106,181			120,288
Total oil and gas properties	2,487,135			2,359,474
Other property and equipment	151,929			143,285
Total property and equipment	2,639,064			2,502,759
Accumulated depreciation, depletion and amortization	(827,511		)	(725,184		)
	$	1,811,553		$	1,777,575


7.	Long-Term Debt

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



	June 30, 2012			December 31, 2011
Revolving credit facility	$	180,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)	294,144			293,561
Senior notes due 2019	300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)	4,837			4,746
	778,981			697,307
Less: Current portion of long-term debt	(4,837		)	(4,746		)
	$	774,144		$	692,561

Revolving Credit Facility

In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver has a borrowing base that is redetermined semi-annually. Upon the closing of the sale of our assets in the Appalachian region on July 31, 2012, our borrowing base under the Revolver was decreased by $70 million to a level of $230 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. We had letters of credit of $1.7 million outstanding as of June 30, 2012. As of June 30, 2012, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $118.3 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (the “Adjusted LIBOR”), plus an applicable margin ranging from 1.500% to 2.500% or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2012, the effective interest rate on the borrowings under the Revolver was 2.2500%.

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

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

to 1.0 for periods ending after June 30, 2013.

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

2016 Senior Notes

The 2016 Senior Notes were originally sold at 97% of par equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. Beginning in June 2013, we may redeem all or part of the 2016 Senior Notes at a redemption price starting at 105.188% of the principal amount and reducing to 100% in June 2015 and thereafter. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2019 Senior Notes

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

Convertible Notes

The 4.50% Convertible Senior Subordinated Notes due 2012 (“Convertible Notes”) bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes rank senior in right of payment to any of our future junior subordinated indebtedness and structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.

The Convertible Notes are represented by a liability component classified as current maturities of long-term debt, net of discount, and an equity component representing the convertible feature which is included in additional paid-in capital in shareholders’ equity. The effective interest rate on the liability component of the Convertible Notes for all periods presented was 8.5%. The $4.9 million of outstanding principal amount due on the Convertible Notes will be paid on November 15, 2012 and will be funded by cash on hand or by borrowings under the Revolver.

In connection with a tender offer completed in April 2011, the Company repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, including a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded from the net proceeds of the 2019 Senior Notes offering.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes the carrying amount of the components of the Convertible Notes as of the dates presented:



	June 30, 2012			December 31, 2011
Principal	$	4,915		$	4,915
Unamortized discount	(78		)	(169		)
Net carrying amount of liability component	$	4,837		$	4,746
Carrying amount of equity component	$	35,201		$	35,201

The following table summarizes the amounts recognized as components of interest expense attributable to the Convertible Notes for the periods presented:



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Contractual interest expense	$	56	$	421	$	111	$	3,009
Accretion on original issue discount	46		318		91		2,265
Amortization of debt issuance costs	7		55		14		389
	$	109	$	794	$	216	$	5,663


8.	Additional Balance Sheet Detail

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



	June 30, 2012		December 31, 2011
Other current assets:
Tubular inventory and well materials	$	5,588	$	14,251
Prepaid expenses	1,262		699
	$	6,850	$	14,950
Other assets:
Debt issuance costs	$	15,617	$	16,993
Assets of supplemental employee retirement plan ("SERP")	3,298		3,088
Other	1,890		51
	$	20,805	$	20,132
Accounts payable and accrued liabilities:
Trade accounts payable	$	37,040	$	30,186
Drilling costs	16,116		30,948
Royalties	11,977		15,235
Production and franchise taxes	5,881		3,495
Compensation	4,827		5,186
Interest	6,208		5,964
Other	2,173		3,490
	$	84,222	$	94,504
Other liabilities:
Asset retirement obligations	$	6,440	$	6,283
Defined benefit pension obligations	1,694		1,763
Postretirement health care benefit obligations	3,011		3,022
Deferred compensation - SERP obligation and other	3,416		3,172
Other	2,014		1,647
	$	16,575	$	15,887

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


9.	Fair Value Measurements

We apply the authoritative accounting provisions for measuring the fair values 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. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of June 30, 2012, 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:



	June 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2016	$	285,000	$	294,144	$	319,500	$	293,561
Senior Notes due 2019	244,500		300,000		280,500		300,000
Convertible Notes	4,915		4,837		4,925		4,746
	$	534,415	$	598,981	$	604,925	$	598,307

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 fair values of those assets and liabilities as of the dates presented:



	As of June 30, 2012
	Fair Value Measurement			Fair Value Measurement Classification
Description	Fair Value Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	26,763		$	—		$	26,763		$	—
Commodity derivative assets - noncurrent	12,664			—			12,664			—
Assets of SERP	3,298			3,298			—			—
Liabilities:
Commodity derivative liabilities - current	(617		)	—			(617		)	—
Commodity derivative liabilities - noncurrent	(1,651		)	—			(1,651		)	—
Deferred compensation - SERP obligation and other	(3,411		)	(3,411		)	—			—
	$	37,046		$	(113	)	$	37,159		$	—



	As of December 31, 2011
	Fair Value Measurement			Fair Value Measurement Classification
Description	Fair Value Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets – current	$	18,987		$	—		$	18,987		$	—
Assets of SERP	3,088			3,088			—			—
Liabilities:
Commodity derivative liabilities - current	(3,549		)	—			(3,549		)	—
Commodity derivative liabilities - noncurrent	(6,850		)	—			(6,850		)	—
Deferred compensation - SERP obligation and other	(3,168		)	(3,168		)	—			—
	$	8,508		$	(80	)	$	8,588		$	—

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 or six months ended June 30, 2012 and 2011.

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 NYMEX Henry Hub gas and West Texas Intermediate crude oil 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 obligation and other: 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 include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of asset retirement obligations (“AROs”). The factors used to determine fair value for purposes of impairment testing 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 fair value estimates as level 3 inputs.


10.	Commitments and Contingencies

Commitments

Our most significant commitments consist of the purchase of oil and gas well drilling services, capacity utilization under firm transportation service agreements and operating leases for field and office equipment and office space, as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.

We have contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we will no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we expect to record a charge of approximately $15 million to $18 million in the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Contingencies - Legal and Regulatory

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of June 30, 2012. In addition, as of June 30, 2012, we have an ARO liability of approximately $6.4 million attributable to the plugging of abandoned wells.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


11.	Shareholders’ Equity

The following table summarizes the components of our shareholders’ equity and the changes therein as of and for the six months ended June 30, 2012 and 2011:



	Balance as of December 31, 2011			Net Loss			Dividends Paid ($0.1125 per share)			All Other Changes			Balance as of June 30, 2012
Common stock	$	270		$	—		$	—		$	1		$	271
Paid-in capital	690,131			—			—			2,947			693,078
Retained earnings	157,242			(17,537		)	(5,176		)	—			134,529
Deferred compensation obligation	3,620			—			—			(588		)	3,032
Accumulated other comprehensive loss	(1,084		)	—			—			46			(1,038		)
Treasury stock	(3,870		)	—			—			586			(3,284		)
Total shareholders' equity	$	846,309		$	(17,537	)	$	(5,176	)	$	2,992		$	826,588



	Balance as of December 31, 2010			Net Loss			Dividends Paid ($0.1125 per share)			All Other Changes			Balance as of June 30, 2011
Common stock	$	267		$	—		$	—		$	2		$	269
Paid-in capital	680,981			—			—			4,578			685,559
Retained earnings	300,473			(98,258		)	(5,156		)	—			197,059
Deferred compensation obligation	2,743			—			—			492			3,235
Accumulated other comprehensive loss	(938		)	—			—			68			(870		)
Treasury stock	(3,250		)	—			—			(395		)	(3,645		)
Total shareholders' equity	$	980,276		$	(98,258	)	$	(5,156	)	$	4,745		$	881,607


12.	Share-Based Compensation

Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. Generally, stock options granted under our stock compensation plans vest over a three-year period, with one-third vesting in each year. Common stock and deferred common stock units granted under our stock compensation plans vest immediately, and we recognize compensation expense related to those grants on the grant date. Restricted stock and restricted stock units granted under our stock compensation plans vest over a three-year period, either at the end of the three years or with one-third vesting in each year. We recognize compensation expense related to our stock compensation plans in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations.

Equity-Classified Awards

Most of the awards issued under our stock compensation plans are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The recognition of compensation cost attributable to these awards is a non-cash item of expense.

Liability-Classified Awards

In February 2012, we granted performance-based restricted stock units (“PBRSUs”) to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Equity-classified awards:
Stock option plans	$	950	$	1,379	$	2,158	$	2,787
Common, deferred, restricted and time-based restricted unit plans	386		634		793		1,022
	1,336		2,013		2,951		3,809
Liability-classified awards	553		—		625		—
	$	1,889	$	2,013	$	3,576	$	3,809


13.	Restructuring Activities

During 2011, we completed an organizational restructuring due primarily to our decision to exit the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. We terminated approximately 40 employees and closed our regional office in Tulsa, Oklahoma. Accordingly, we recorded a charge and recognized an obligation in connection with the long-term lease of that office. Activities recorded during the periods ended June 30, 2012 that were attributable to this restructuring included cash payments and accretion of the lease obligation and the cash payment of termination benefits accrued during 2011. In addition, we adjusted the lease obligation as a result of a change in estimated sub-lease rental income. Activities recorded during the periods ended June 30, 2011 are attributable to restructuring actions taken during periods prior to 2011. Restructuring charges, including the accretion of the lease obligation, are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations.

The following table summarizes our restructuring-related obligations as of and for the periods presented:



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Balance at beginning of period	$	475		$	—		$	576		$	64
Employee, office and other costs accrued	(145		)	52			(148		)	70
Cash payments, net	(79		)	(52		)	(177		)	(134		)
Balance at end of period	$	251		$	—		$	251		$	—

In the third quarter of 2012, we expect to record restructuring and certain exit costs in connection with the sale of our Appalachian properties, including those attributable to the planned closing of our office in Canonsburg, Pennsylvania.


14.	Impairments

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



	Three Months Ended June 30,				Six Months Ended June 30,
	2012		2011		2012		2011
Oil and gas properties	$	28,481	$	71,071	$	28,481	$	71,071
Other	135		—		135		—
	$	28,616	$	71,071	$	28,616	$	71,071

During the quarter ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the quarter ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


15.	Interest Expense

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Interest on borrowings and related fees	$	14,289		$	13,120		$	28,306		$	23,867
Accretion on original issue discount	341			583			674			2,788
Amortization of debt issuance costs	694			895			1,376			1,962
Capitalized interest	(240		)	(455		)	(498		)	(990		)
	$	15,084		$	14,143		$	29,858		$	27,627


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 June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Net loss	$	(5,638	)	$	(71,918	)	$	(17,537	)	$	(98,258	)
Weighted-average shares, basic	46,030			45,768			45,988			45,724
Effect of dilutive securities¹	—			—			—			—
Weighted-average shares, diluted	46,030			45,768			45,988			45,724

____________________________________________________________________________

¹For each of the three and six month periods ended June 30, 2012 and 2011, an amount less than 0.1 million of potentially dilutive securities, including the Convertible Notes, stock options, restricted stock and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

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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 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 and natural gas;


•	our ability to develop, explore for, acquire and replace oil and 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, natural gas liquids and natural gas;


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


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


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


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


•	drilling and operating risks;


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


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


•	leasehold terms expiring before production can be established;


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


•	the timing of receipt of necessary regulatory permits;


•	the effect of commodity and financial derivative arrangements;


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


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


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


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


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


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


•	other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

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

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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.

Overview of Business

We are an independent oil and gas company engaged in the exploration, development and production of oil and natural gas in various domestic onshore regions. We have a geographically diverse asset base with areas of operations in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of December 31, 2011, we had proved natural gas and oil reserves of approximately 883 billion cubic feet equivalent, or Bcfe. As discussed in the Key Developments that follow, our total reserves were reduced by approximately106 Bcfe subsequent to the sale of our Appalachian properties in July 2012. Our current operations include primarily the drilling of unconventional development wells and exploring for primarily unconventional reserves.

We are currently focused on the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in our Mid-Continent region through participation in wells drilled by our joint venture partner.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
Total production (MMcfe)	10,653			11,699			21,527			23,870
Daily production (MMcfe per day)	117.1			128.5			118.3			132.0
Daily gas production (MMcf per day)	64.4			97.4			66.8			102.7
Daily oil and NGL production (Bbl per day)	8,780			5,180			8,570			4,860
Product revenues, as reported	$	76,241		$	73,009		$	158,921		$	140,702
Product revenues, as adjusted for derivatives	$	81,806		$	77,142		$	172,467		$	151,579
Operating loss	$	(38,043	)	$	(80,713	)	$	(41,465	)	$	(109,242	)
Interest expense	$	15,084		$	14,143		$	29,858		$	27,627
Cash provided by operating activities	$	45,024		$	34,323		$	115,725		$	63,759
Cash paid for capital expenditures	$	93,767		$	110,352		$	188,236		$	211,081
Cash and cash equivalents at end of period							$	11,532		$	30,681
Debt outstanding, net of discounts, at end of period							$	778,981		$	597,668
Credit available under revolving credit facility at end of period¹							$	118,282		$	160,730
Net development wells drilled	4.7			12.0			12.2			14.4
Net exploratory wells drilled	2.9			1.1			4.8			6.4

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

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Key Developments

Through the date of filing this Quarterly Report on Form 10-Q, the following general business developments and corporate actions had an impact on the financial reporting and disclosure of our results of operations and financial position: (i) drilling results in the Eagle Ford Shale and other plays, (ii) continuing to shift the focus of our production from natural gas to crude oil and natural gas liquids, or NGLs, (iii) executing an agreement to sell our Appalachian assets and (iv) hedging a portion of our crude oil production for the calendar years 2012 through 2014 to the levels permitted by our revolving credit agreement, or Revolver, and our internal policies.

Drilling Results and Future Development

During the six months ended June 30, 2012, we drilled a total of 20 gross (16.9 net) wells, including 14 gross (11.7 net) development wells and five gross (4.7 net) exploratory wells in the Eagle Ford Shale and one gross (0.5 net) development well in the Granite Wash.

We currently have two rigs drilling in the Eagle Ford Shale. We have drilled a total of 53 wells since we began drilling operations in this play during the first half of 2011. Of the total wells drilled, 51 (42.0 net) wells are producing and two are in progress as of July 31, 2012. The average peak gross production rate per well for 44 of these wells which had full-length laterals was approximately 1,001 barrels of oil equivalent per day, or BOEPD. Our Eagle Ford Shale production was approximately 6,550 net BOEPD during the second quarter of 2012, with oil comprising 84 percent, NGLs comprising nine percent and natural gas comprising seven percent. We have allocated over 90 percent of our capital expenditures during 2012 to activities in the Eagle Ford Shale.

Included in the totals presented above for the Eagle Ford Shale are our first four (3.8 net) exploratory wells in Lavaca County, Texas drilled in connection with a joint exploration agreement with an industry partner that we entered into in December 2011. Under the terms of the agreement, we must commence drilling on six wells by September 1, 2012 to earn our entire interest in the 13,500 acre area of mutual interest, or AMI, and must carry our partner on its working interest share of the costs of the first three wells. We are currently drilling our fifth well of the six well obligation and based on our progress through July 31, 2012, we expect to complete this requirement and earn our maximum interest in approximately 8,000 net acres. Depending upon the future participation elections made by our partners, our ultimate working interest in wells drilled in the AMI is expected to be at least 57%.

Production Focus

During the past two years, we have allocated approximately 80% of our capital expenditures to explore and develop primarily oil and NGL-rich areas, primarily in the Eagle Ford Shale in South Texas. Accordingly, we are continuing to transform our production profile away from natural gas to oil and NGLs. Approximately 44% of our total production on an equivalent basis during the six months ended June 30, 2012 was attributable to oil and NGLs, an increase of approximately 76% over the prior year period and approximately 5% over the three month period ended March 31, 2012. For the six months ended June 30, 2012, approximately 84% of our product revenues were attributable to oil and NGLs, an increase of approximately 118% over the corresponding prior year period.

Disposition of Appalachian Assets

On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and purchase and sale adjustments. The transaction had an effective date of January 1, 2012. The properties sold included vertical and horizontal coalbed methane and conventional properties as well as royalty interests. The properties had net production of approximately 20 million cubic feet of natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. As a result of the divestiture, our 2012 production will decrease by an estimated 2.9 Bcfe. Estimated proved reserves associated with the properties, as determined by our third party reserve engineers as of December 31, 2011, were approximately 106 Bcfe, of which 96 percent were proved developed and 100 percent were natural gas. Also included in the group of assets sold was a gathering system. Upon the closing of the transaction, our borrowing base under the Revolver was decreased by $70 million to a level of $230 million.

During the quarter ended June 30, 2012, we recognized an impairment of $28.6 million with respect to these assets. In the third quarter of 2012, we expect to record certain restructuring and exit costs in connection with the sale, including those attributable to the planned closing of our office in Canonsburg, Pennsylvania. Furthermore, we have contractual commitments

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for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we will no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we expect to record a charge of approximately $15 million to $18 million in the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Commodity Hedging Activities

In January 2012, we amended our Revolver to expand the potential volume available for hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves. As of June 30, 2012, we have hedged the maximum volume of oil production as permitted under the terms of the Revolver for calendar years 2012 through 2014. For the remainder of 2012, we have hedged approximately 67 percent of our estimated oil production at weighted-average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel. For 2013, we have approximately 35 to 40 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $98.61 and $102.09 per barrel. For 2014, we have approximately 15 to 20 percent of our estimated oil production hedged at a weighted-average swap price of $100.33 per barrel. Our natural gas hedges represent approximately 32 percent of our estimated production for the balance of the year at a weighted-average swap price of $5.24 per MMBtu. At this time, we have no hedges in place for our estimated natural gas production beyond 2012.

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Results of Operations

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

The following table sets forth a summary of certain operating and financial performance for the periods presented:



	Three Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)	5,859			8,869			(3,010		)	(34	)%
Crude oil (MBbl)	572			219			353			161	%
NGLs (MBbl)	227			253			(26		)	(10	)%
Total production (MMcfe)	10,653			11,699			(1,046		)	(9	)%
Realized prices, before derivatives:
Natural gas ($/Mcf)	$	1.76		$	4.32		$	(2.56	)	(59	)%
Crude oil ($/Bbl)	102.14			98.48			3.66			4	%
NGLs ($/Bbl)	33.23			52.04			(18.81		)	(36	)%
Total ($/Mcfe)	$	7.16		$	6.24		$	0.92		15	%
Revenues
Natural gas	$	10,303		$	38,300		$	(27,997	)	(73	)%
Crude oil	58,382			21,548			36,834			171	%
Natural gas liquids (NGLs)	7,556			13,161			(5,605		)	(43	)%
Total product revenues	76,241			73,009			3,232			4	%
Gain on sales of property and equipment, net	78			(28		)	106			NM
Other	526			637			(111		)	(17	)%
Total revenues	76,845			73,618			3,227			4	%
Operating expenses
Lease operating	9,264			10,787			1,523			14	%
Gathering, processing and transportation	4,391			4,281			(110		)	(3	)%
Production and ad valorem taxes	(254		)	2,834			3,088			109	%
General and administrative	11,747			12,954			1,207			9	%
Exploration	9,384			19,368			9,984			52	%
Depreciation, depletion and amortization	51,740			33,036			(18,704		)	(57	)%
Impairments	28,616			71,071			42,455			60	%
Total operating expenses	114,888			154,331			39,443			26	%
Operating loss	(38,043		)	(80,713		)	42,670			53	%
Other income (expense)
Interest expense	(15,084		)	(14,143		)	(941		)	(7	)%
Loss on extinguishment of debt	—			(24,238		)	24,238			NM
Derivatives	43,826			7,001			36,825			NM
Other	28			129			(101		)	(78	)%
Loss before income taxes	(9,273		)	(111,964		)	102,691			92	%
Income tax benefit	3,635			40,046			(36,411		)	(91	)%
Net loss	$	(5,638	)	$	(71,918	)	$	66,280		92	%
NM - Not meaningful

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Production

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



Natural gas	Three Months Ended June 30,		Favorable		Three Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas	1,789	2,787	(998	)	19.7	30.6	(10.9	)	(36	)%
Appalachia	1,952	2,256	(303	)	21.5	24.8	(3.3	)	(13	)%
Mid-Continent	841	2,161	(1,320	)	9.2	23.7	(14.5	)	(61	)%
Mississippi	1,276	1,665	(388	)	14.0	18.3	(4.3	)	(23	)%
	5,859	8,869	(3,010	)	64.4	97.4	(33	)	(34	)%



Crude oil	Three Months Ended June 30,			Favorable		Three Months Ended June 30,			Favorable
	2012	2011		(Unfavorable)		2012	2011		(Unfavorable)		% Change
	(MBbl)					(MBbl per day)
Texas	518.3	120.1		398.2		5.70	1.32		4.38		332	%
Appalachia	0.3	(0.7	)	1.0		—	(0.01	)	0.01		100	%
Mid-Continent	49.2	94.0		(44.8	)	0.54	1.03		(0.49	)	(48	)%
Mississippi	3.8	5.4		(1.6	)	0.04	0.06		(0.02	)	(33	)%
	571.6	218.8		352.8		6.28	2.40		3.88		162	%



NGLs	Three Months Ended June 30,			Favorable		Three Months Ended June 30,		Favorable
	2012	2011		(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)					(MBbl per day)
Texas	118.1	119.4		(1.3	)	1.30	1.31	(0.01	)	(1	)%
Appalachia	0.2	(0.1	)	0.3		—	—	—		NM
Mid-Continent	109.1	133.6		(24.5	)	1.20	1.47	(0.27	)	(18	)%
	227.4	252.9		(25.5	)	2.50	2.78	(0.28	)	(10	)%



Combined total	Three Months Ended June 30,		Favorable		Three Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcfe)				(MMcfe per day)
Texas	5,608	4,224	1,384		61.6	46.4	15.2		33	%
Appalachia	1,955	2,251	(296	)	21.5	24.7	(3.2	)	(13	)%
Mid-Continent	1,790	3,527	(1,736	)	19.7	38.8	(19.1	)	(49	)%
Mississippi	1,299	1,697	(398	)	14.3	18.6	(4.3	)	(23	)%
	10,653	11,699	(1,046	)	117.1	128.5	(11.4	)	(9	)%
Certain results in the tables above may not calculate due to rounding.

The decline in total production during the quarter ended June 30, 2012 compared to the corresponding quarter of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Arkoma Basin properties in August 2011. The effect of the sale of the Arkoma Basin properties was approximately 0.6 Bcfe during the quarter. The natural declines in production were partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 45% of total production on an equivalent basis in the quarter ended June 30, 2012 was attributable to oil and NGLs, a 69% increase over the prior year quarter. The shift in production mix reflects our focus on emerging oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the quarter ended June 30, 2012, our Eagle Ford Shale production of 3.6 Bcfe represented 34% of our total production. We had approximately 0.5 Bcfe of production from this play during the 2011 quarter.

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Product Revenues and Prices

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



Natural gas	Three Months Ended June 30,				Favorable			Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcf)
Texas	$	3,254	$	13,126	$	(9,872	)	$	1.82	$	4.71	$	(2.89	)
Appalachia	3,962		9,812		(5,850		)	2.03		4.35		(2.32		)
Mid-Continent	200		7,851		(7,651		)	0.24		3.63		(3.39		)
Mississippi	2,887		7,511		(4,624		)	2.26		4.51		(2.25		)
	$	10,303	$	38,300	$	(27,997	)	$	1.76	$	4.32	$	(2.56	)



Crude oil	Three Months Ended June 30,					Favorable			Three Months Ended June 30,				Favorable
	2012		2011			(Unfavorable)			2012		2011		(Unfavorable)
									($ per Bbl)
Texas	$	53,806	$	11,568		$	42,238		$	103.81	$	96.32	$	7.49
Appalachia	27		(42		)	69			90.00		60.00		30.00
Mid-Continent	4,164		9,445			(5,281		)	84.63		100.48		(15.85		)
Mississippi	385		577			(192		)	101.32		106.85		(5.53		)
	$	58,382	$	21,548		$	36,834		$	102.14	$	98.48	$	3.66



NGLs	Three Months Ended June 30,					Favorable			Three Months Ended June 30,				Favorable
	2012		2011			(Unfavorable)			2012		2011		(Unfavorable)
									($ per Bbl)
Texas	$	3,805	$	6,166		$	(2,361	)	$	32.22	$	51.64	$	(19.42	)
Appalachia	10		(1		)	11			50.00		10.00		40.00
Mid-Continent	3,741		6,996			(3,255		)	34.29		52.37		(18.08		)
	$	7,556	$	13,161		$	(5,605	)	$	33.23	$	52.04	$	(18.81	)



Combined total	Three Months Ended June 30,				Favorable			Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcfe)
Texas	$	60,865	$	30,860	$	30,005		$	10.85	$	7.31	$	3.54
Appalachia	3,999		9,769		(5,770		)	2.05		4.34		(2.29		)
Mid-Continent	8,105		24,292		(16,187		)	4.53		6.89		(2.36		)
Mississippi	3,272		8,088		(4,816		)	2.52		4.77		(2.25		)
	$	76,241	$	73,009	$	3,232		$	7.16	$	6.24	$	0.92

As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $1.5 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from other partners in our Mid-Continent region. The following table provides an analysis of the change in our revenues for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011:



	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(12,998	)	$	(14,999	)	$	(27,997	)
Crude oil	34,724			2,110			36,834
NGLs	(1,326		)	(4,279		)	(5,605		)
	$	20,400		$	(17,168	)	$	3,232

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Effects of Derivatives

Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge natural gas and crude oil prices. During the three months ended June 30, 2012 and 2011, we received $5.6 million and $4.1 million in net cash settlements from oil and gas derivatives.

The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Three Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Natural gas revenues as reported	$	10,303		$	38,300		$	(27,997	)	(73	)%
Cash settlements on natural gas derivatives, net	5,630			4,261			1,369			32	%
Natural gas revenues adjusted for derivatives	$	15,933		$	42,561		$	(26,628	)	(63	)%
Natural gas prices per Mcf, as reported	$	1.76		$	4.32		$	(2.56	)	(59	)%
Cash settlements on natural gas derivatives per Mcf	0.96			0.48			0.48			100	%
Natural gas prices per Mcf adjusted for derivatives	$	2.72		$	4.80		$	(2.08	)	(43	)%
Crude oil revenues as reported	$	58,382		$	21,548		$	36,834		171	%
Cash settlements on crude oil derivatives, net	(65		)	(128		)	63			49	%
Crude oil revenues adjusted for derivatives	$	58,317		$	21,420		$	36,897		172	%
Crude oil prices per Bbl, as reported	$	102.14		$	98.48		$	3.66		4	%
Cash settlements on crude oil derivatives per Bbl	(0.11		)	(0.59		)	0.48			81	%
Crude oil prices per Bbl adjusted for derivatives	$	102.03		$	97.89		$	4.14		4	%

Gain on Sales of Property and Equipment

We recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.

Other Income

Other income decreased during the quarter ended June 30, 2012 due primarily to lower gathering, transportation, compression and salt water disposal fees.

Operating Expenses

As discussed individually below, we experienced an absolute decrease in several operating expenses. Due primarily to declining natural gas production, however, certain expenses increased on a unit of production basis. The following table summarizes certain of our operating expenses per Mcfe for the periods presented:



	Three Months Ended June 30,					Favorable
	2012			2011		(Unfavorable)			% Change
Lease operating	$	0.87		$	0.92	$	0.05		5	%
Gathering, processing and transportation	0.41			0.37		(0.04		)	(11	)%
Production and ad valorem taxes	(0.02		)	0.24		0.26			108	%
General and administrative excluding share-based compensation and restructuring charges	0.94			0.93		(0.01		)	(1	)%
General and administrative	1.10			1.11		0.01			1	%
Depreciation, depletion and amortization	4.86			2.82		(2.04		)	(72	)%

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Lease Operating

Lease operating expense decreased on an absolute basis and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs. Certain expense decreases were also attributable to the sale of our Arkoma Basin properties. Cost decreases were partially offset by higher utility, field contracting, well tending, chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased slightly during the 2012 period, despite lower overall product volume, due primarily to a higher amount of unrecovered firm transportation costs in the Appalachian region.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased during the 2012 period due primarily to recently approved Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells for the period of July 1, 2009 through June 30, 2011. Rebates were also recognized for certain Texas wells. Production taxes also decreased due to lower natural gas volume and prices in the 2012 period as compared to the 2011 period.

General and Administrative

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



	Three Months Ended June 30,					Favorable
	2012			2011		(Unfavorable)			% Change
Recurring general and administrative expenses	$	10,006		$	10,889	$	883		8	%
Share-based compensation (liability-classified)	553			—		(553		)	NM
Share-based compensation (equity-classified)	1,336			2,013		677			34	%
Restructuring expenses	(148		)	52		200			NM
	$	11,747		$	12,954	$	1,207		9	%

Recurring general and administrative expenses decreased due to reduced headcount and lower support costs primarily attributable to restructuring actions taken during 2011. Liability-classified share-based compensation is attributable to our performance-based restricted stock unit awards, which are payable in cash upon achievement of certain market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the 2012 period due primarily to a lower number of awards granted. Restructuring expenses include an adjustment to the lease obligation for our former Tulsa, Oklahoma office due to a change in estimated sub-lease rental income.

Exploration

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



	Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)		% Change
Unproved leasehold amortization	$	8,284	$	11,966	$	3,682	31	%
Dry hole costs	—		2,116		2,116		100	%
Geological and geophysical costs	781		4,302		3,521		82	%
Other, primarily delay rentals	319		984		665		68	%
	$	9,384	$	19,368	$	9,984	52	%

Unproved leasehold amortization declined during the 2012 period as certain properties primarily in the Eagle Ford Shale were transferred to proved in the second half of 2011 and the first half of 2012. The prior year period included dry hole costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, geological and geophysical and other

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exploration costs decreased during the 2012 period as our efforts are concentrated on the Eagle Ford Shale while the prior year period included multiple exploratory prospect activities.

Depreciation, Depletion and Amortization (DD&A)

The following tables set forth the components of DD&A and the nature of the variances for the periods presented:



	Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Depletion	$	50,262	$	31,606	$	(18,656	)	(59	)%
Depreciation - Oil and gas operations	997		619		(378		)	(61	)%
Depreciation - Corporate	367		679		312			46	%
Amortization	114		132		18			14	%
	$	51,740	$	33,036	$	(18,704	)	(57	)%



	DD&A Variance Due to
	Production		Rates			Total
Three months ended June 30, 2012 compared to 2011	$	2,955	$	(21,659	)	$	(18,704	)

The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $4.72 per Mcfe for the 2012 period from $2.70 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Impairments

The following table summarizes the impairments recorded for the periods presented:



	Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Oil and gas properties	$	28,481	$	71,071	$	42,590		60	%
Other	135		—		(135		)	NM
	$	28,616	$	71,071	$	42,455		60	%

During the quarter ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the quarter ended ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

Interest Expense

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



	Three Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Interest on borrowings and related fees	$	14,289		$	13,120		$	(1,169	)	(9	)%
Accretion of original issue discount	341			583			242			42	%
Amortization of debt issuance costs	694			895			201			22	%
Capitalized interest	(240		)	(455		)	(215		)	(47	)%
	$	15,084		$	14,143		$	(941	)	(7	)%

The issuance of the 7.25% Senior Notes due 2019, or 2019 Senior Notes, and borrowings under the Revolver, offset by

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the repurchase of approximately 98% of the outstanding 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes, with an effective interest rate of 8.5%, resulted in an approximate $184 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental fees paid in cash.

Derivatives

The following table summarizes the components of our derivative income for the periods presented:



	Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)		% Change
Oil and gas derivative unrealized gain	$	36,257	$	1,864	$	34,393	NM
Oil and gas derivative realized gain	5,564		4,133		1,431		35	%
Interest rate swap unrealized gain	599		106		493		NM
Interest rate swap realized gain	1,406		898		508		57	%
	$	43,826	$	7,001	$	36,825	NM

We received cash settlements of $7.0 million during the quarter ended June 30, 2012 and $5.0 million during the comparable period in 2011. Cash settlements in the 2012 period included $1.2 million in connection with the termination of our interest rate swap agreement. The significant increase in the unrealized gain on commodity derivatives was due primarily to oil prices declining below our hedged prices.

Other Income

Other income decreased during the 2012 period due primarily to lower interest income earned on average cash balances.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2012 was 39.2% compared to 35.8% for the 2011 period. Due to operating losses incurred, we recognized income tax benefits during both periods.

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Results of Operations

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

The following table sets forth a summary of certain operating and financial performance for the periods presented:



	Six Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)	12,153			18,594			(6,441		)	(35	)%
Crude oil (MBbl)	1,120			407			713			175	%
NGLs (MBbl)	442			473			(31		)	(7	)%
Total production (MMcfe)	21,527			23,870			(2,343		)	(10	)%
Realized prices, before derivatives:
Natural gas ($/Mcf)	$	2.07		$	4.27		$	(2.20	)	(52	)%
Crude oil ($/Bbl)	104.55			93.80			10.75			11	%
NGLs ($/Bbl)	37.60			48.82			(11.22		)	(23	)%
Total ($/Mcfe)	$	7.38		$	5.89		$	1.49		25	%
Revenues
Natural gas	$	25,189		$	79,489		(54,300		)	(68	)%
Crude oil	117,105			38,131			78,974			207	%
Natural gas liquids (NGLs)	16,627			23,082			(6,455		)	(28	)%
Total product revenues	158,921			140,702			18,219			13	%
Gain on sales of property and equipment, net	834			452			382			85	%
Other	1,501			1,047			454			43	%
Total revenues	161,256			142,201			19,055			13	%
Operating expenses
Lease operating	18,407			21,064			2,657			13	%
Gathering, processing and transportation	8,545			8,309			(236		)	(3	)%
Production and ad valorem taxes	3,326			7,898			4,572			58	%
General and administrative	23,888			26,306			2,418			9	%
Exploration	17,382			48,916			31,534			64	%
Depreciation, depletion and amortization	102,557			67,879			(34,678		)	(51	)%
Impairments	28,616			71,071			42,455			60	%
Total operating expenses	202,721			251,443			48,722			19	%
Operating loss	(41,465		)	(109,242		)	67,777			62	%
Other income (expense)
Interest expense	(29,858		)	(27,627		)	(2,231		)	(8	)%
Loss on extinguishment of debt	—			(24,238		)	24,238			NM
Derivatives	43,521			8,329			35,192			NM
Other	29			273			(244		)	(89	)%
Loss before income taxes	(27,773		)	(152,505		)	124,732			82	%
Income tax benefit	10,236			54,247			(44,011		)	(81	)%
Net loss	$	(17,537	)	$	(98,258	)	$	80,721		82	%
NM - Not meaningful

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Production

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



Natural gas	Six Months Ended June 30,		Favorable		Six Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas	3,620	5,553	(1,934	)	19.9	30.7	(10.8	)	(35	)%
Appalachia	4,014	4,616	(601	)	22.1	25.5	(3.4	)	(13	)%
Mid-Continent	1,949	4,932	(2,983	)	10.7	27.2	(16.5	)	(61	)%
Mississippi	2,570	3,494	(924	)	14.1	19.3	(5.2	)	(27	)%
	12,153	18,594	(6,441	)	66.8	102.7	(35.9	)	(35	)%



Crude oil	Six Months Ended June 30,			Favorable		Six Months Ended June 30,		Favorable
	2012	2011		(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)					(MBbl per day)
Texas	997.5	177.1		820.5		5.48	0.98	4.50		459	%
Appalachia	0.5	(0.2	)	0.7		—	—	—		NM
Mid-Continent	114.3	219.1		(104.8	)	0.63	1.21	(0.58	)	(48	)%
Mississippi	7.8	10.6		(2.8	)	0.04	0.06	(0.02	)	(33	)%
	1,120.1	406.5		713.6		6.15	2.25	3.90		173	%



NGLs	Six Months Ended June 30,		Favorable		Six Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)				(MBbl per day)
Texas	224.5	239.0	(14.6	)	1.23	1.32	(0.09	)	(7	)%
Appalachia	0.4	0.1	0.3		—	—	—		NM
Mid-Continent	217.3	233.6	(16.3	)	1.19	1.29	(0.10	)	(8	)%
	442.2	472.8	(30.6	)	2.42	2.61	(0.19	)	(7	)%



Combined total	Six Months Ended June 30,		Favorable		Six Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcfe)				(MMcfe per day)
Texas	10,952	8,050	2,902		60.2	44.5	15.7		35	%
Appalachia	4,020	4,615	(595	)	22.1	25.5	(3.4	)	(13	)%
Mid-Continent	3,939	7,648	(3,710	)	21.6	42.3	(20.7	)	(49	)%
Mississippi	2,617	3,557	(940	)	14.4	19.7	(5.3	)	(27	)%
	21,527	23,870	(2,343	)	118.3	132.0	(13.7	)	(10	)%
Certain results in the tables above may not calculate due to rounding.

The decline in total production during the six months ended June 30, 2012 compared to the corresponding period of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Arkoma Basin properties in August 2011. The effect of the sale of the Arkoma Basin properties was approximately 1.6 Bcfe during the six month period. The natural declines in production were otherwise essentially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 44% of total production on an equivalent basis in the six months ended June 30, 2012 was attributable to oil and NGLs, a 76% increase over the prior year period. The shift in production mix reflects our focus on emerging oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the six months ended June 30, 2012, our Eagle Ford Shale production of 6.7 Bcfe represented 31% of our total production. We had approximately 0.7 Bcfe of production from this play during the first half of 2011.

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Product Revenues and Prices

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



Natural gas	Six Months Ended June 30,				Favorable			Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcf)
Texas	$	7,487	$	23,764	$	(16,277	)	$	2.07	$	4.28	$	(2.21	)
Appalachia	9,385		19,588		(10,203		)	2.34		4.24		(1.90		)
Mid-Continent	1,735		20,914		(19,179		)	0.89		4.24		(3.35		)
Mississippi	6,582		15,223		(8,641		)	2.56		4.36		(1.80		)
	$	25,189	$	79,489	$	(54,300	)	$	2.07	$	4.27	$	(2.20	)



Crude oil	Six Months Ended June 30,					Favorable			Six Months Ended June 30,				Favorable
	2012		2011			(Unfavorable)			2012		2011		(Unfavorable)
									($ per Bbl)
Texas	$	105,595	$	16,644		$	88,951		$	105.86	$	93.99	$	11.87
Appalachia	49		(8		)	57			93.16		36.04		57.12
Mid-Continent	10,628		20,430			(9,802		)	93.02		93.25		(0.23		)
Mississippi	833		1,065			(232		)	106.55		100.74		5.81
	$	117,105	$	38,131		$	78,974		$	104.55	$	93.80	$	10.75



NGLs	Six Months Ended June 30,				Favorable			Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)

Texas	$	8,580	$	11,518	$	(2,938	)	$	38.23	$	48.18	$	(9.95	)
Appalachia	21		9		12			52.63		69.23		(16.60		)
Mid-Continent	8,026		11,555		(3,529		)	36.93		49.46		(12.53		)
	$	16,627	$	23,082	$	(6,455	)	$	37.60	$	48.82	$	(11.22	)



Combined total	Six Months Ended June 30,				Favorable			Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)

Texas	$	121,662	$	51,926	$	69,736		$	11.11	$	6.45	$	4.66
Appalachia	9,455		19,589		(10,134		)	2.35		4.24		(1.89		)
Mid-Continent	20,389		52,899		(32,510		)	5.18		6.92		(1.74		)
Mississippi	7,415		16,288		(8,873		)	2.83		4.58		(1.75		)
	$	158,921	$	140,702	$	18,219		$	7.38	$	5.89	$	1.49

As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $2.3 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from other partners in our Mid-Continent region. The following table provides an analysis of the change in our revenues for the six months ended June 30, 2012 as compared to the six months ended June 30, 2011:



	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(27,535	)	$	(26,765	)	$	(54,300	)
Crude oil	66,936			12,038			78,974
NGLs	(1,495		)	(4,960		)	(6,455		)
	$	37,906		$	(19,687	)	$	18,219

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Effects of Derivatives

Our natural gas and crude oil revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge natural gas and crude oil prices. During the six months ended June 30, 2012 and 2011, we received $13.5 million and $10.9 million in net cash settlements from oil and gas derivatives.

The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:



	Six Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Natural gas revenues as reported	$	25,189		$	79,489		$	(54,300	)	(68	)%
Cash settlements on natural gas derivatives, net	13,718			11,230			2,488			22	%
Natural gas revenues adjusted for derivatives	$	38,907		$	90,719		$	(51,812	)	(57	)%
Natural gas prices per Mcf, as reported	$	2.07		$	4.27		$	(2.20	)	(52	)%
Cash settlements on natural gas derivatives per Mcf	1.13			0.60			0.53			88	%
Natural gas prices per Mcf adjusted for derivatives	$	3.20		$	4.87		$	(1.67	)	(34	)%
Crude oil revenues as reported	$	117,105		$	38,131		$	78,974		207	%
Cash settlements on crude oil derivatives, net	(172		)	(353		)	181			51	%
Crude oil revenues adjusted for derivatives	$	116,933		$	37,778		$	79,155		210	%
Crude oil prices per Bbl, as reported	$	104.55		$	93.80		$	10.75		11	%
Cash settlements on crude oil derivatives per Bbl	(0.15		)	(0.87		)	0.72			83	%
Crude oil prices per Bbl adjusted for derivatives	$	104.40		$	92.93		$	11.47		12	%

Gain on Sales of Property and Equipment

In January 2012, we sold our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania for proceeds of $1.0 million, net of transaction costs. We recognized a gain of $0.6 million in connection with this transaction. In addition, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.

Other Income

Other income increased during the six months ended June 30, 2012 due primarily to higher gathering, transportation and compression fees.

Operating Expenses



	Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Lease operating	$	0.86	$	0.88	$	0.02		2	%
Gathering, processing and transportation	0.40		0.35		(0.05		)	(14	)%
Production and ad valorem taxes	0.15		0.33		0.18			55	%
General and administrative excluding share-based compensation and restructuring charges	0.95		0.94		(0.01		)	(1	)%
General and administrative	1.11		1.10		(0.01		)	(1	)%
Depreciation, depletion and amortization	4.76		2.84		(1.92		)	(68	)%

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Lease Operating

Lease operating expense decreased on an absolute and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs. Certain expense decreases were also attributable to the sale of our Arkoma Basin properties. Cost decreases were partially offset by higher field contracting, well tending, water disposal, chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.

Gathering, Processing and Transportation

Production and Ad Valorem Taxes

General and Administrative

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



	Six Months Ended June 30,					Favorable
	2012			2011		(Unfavorable)			% Change
Recurring general and administrative expenses	$	20,460		$	22,427	$	1,967		9	%
Share-based compensation (liability-classified)	625			—		(625		)	NM
Share-based compensation (equity-classified)	2,951			3,809		858			23	%
Restructuring expenses	(148		)	70		218			NM
	$	23,888		$	26,306	$	2,418		9	%

Exploration

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



	Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)		% Change
Unproved leasehold amortization	$	16,455	$	22,557	$	6,102	27	%
Dry hole costs	—		18,524		18,524		100	%
Geological and geophysical costs	358		6,137		5,779		94	%
Other, primarily delay rentals	569		1,698		1,129		66	%
	$	17,382	$	48,916	$	31,534	64	%

Unproved leasehold amortization declined during the 2012 period as certain properties in the Eagle Ford and Marcellus Shales were transferred to proved in the second half of 2011 and the first half of 2012. The prior year period included dry hole

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costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, geological and geophysical and other exploration costs decreased during the 2012 period as our efforts are concentrated on the Eagle Ford Shale while the prior year period included multiple exploratory prospect activities.

Depreciation, Depletion and Amortization (DD&A)

The following tables set forth the components of DD&A and the nature of the variances for the periods presented:



	Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Depletion	$	99,973	$	65,049	$	(34,924	)	(54	)%
Depreciation - Oil and gas operations	1,575		1,237		(338		)	(27	)%
Depreciation - Corporate	780		1,331		551			41	%
Amortization	229		262		33			13	%
	$	102,557	$	67,879	$	(34,678	)	(51	)%



	DD&A Variance Due to
	Production		Rates			Total
Three months ended June 30, 2012 compared to 2011	$	6,663	$	(41,341	)	$	(34,678	)

The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $4.64 per Mcfe for the 2012 period from $2.72 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Impairments

The following table summarizes the impairments recorded for the periods presented:



	Six Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Oil and gas properties	$	28,481	$	71,071	$	42,590		60	%
Other	135		—		(135		)	NM
	$	28,616	$	71,071	$	42,455		60	%

During the six months ended June 30, 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. During the six months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.

Interest Expense

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



	Six Months Ended June 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Interest on borrowings and related fees	$	28,306		$	23,867		$	(4,439	)	(19	)%
Accretion of original issue discount	674			2,788			2,114			76	%
Amortization of debt issuance costs	1,376			1,962			586			30	%
Capitalized interest	(498		)	(990		)	(492		)	(50	)%
	$	29,858		$	27,627		$	(2,231	)	(8	)%

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The issuance of the 2019 Senior Notes and borrowings under the Revolver, offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate of 8.5%, resulted in an approximate $184 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

Derivatives

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



	Six Months Ended June 30,					Favorable
	2012		2011			(Unfavorable)			% Change
Oil and gas derivative unrealized gain (loss)	$	28,570	$	(3,572	)	$	32,142		NM
Oil and gas derivative realized gain	13,545		10,877			2,668			25	%
Interest rate swap unrealized gain	—		126			(126		)	NM
Interest rate swap realized gain	1,406		898			508			57	%
	$	43,521	$	8,329		$	35,192		NM

We received cash settlements of $15.0 million during the six months ended June 30, 2012 and $11.8 million during the comparable period in 2011. The cash settlements in the 2012 period included $1.2 million in connection with the termination of our interest rate swap agreement. The significant increase in the unrealized gain on commodity derivatives was due primarily oil prices declining below our hedged prices.

Other

Other income decreased during the 2012 period due primarily to lower interest income earned on average cash balances.

Income Tax Expense

The effective tax rate for the six months ended June 30, 2012 was 36.9% compared to 35.6% for the 2011 period. Due to operating losses incurred, we recognized income tax benefits during both periods.

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Liquidity and Capital Resources

Sources of Liquidity

We are currently meeting our cash requirements with a combination of operating cash flows, borrowings under the Revolver and proceeds from sales of assets. We have no material debt maturities until 2016. Our 2012 business strategy requires capital expenditures in excess of our operating cash flows. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures such as acquisitions, we plan to fund our capital program for the remainder of 2012 with operating cash flows and borrowings under the Revolver. We recently discontinued our common stock dividend which improves liquidity by increasing available cash flows by approximately $10 million per year. Other potential sources of additional liquidity include an increase in our Revolver borrowing base resulting from an increase in our Eagle Ford Shale proved reserves, third party joint ventures, additional non-strategic asset sales or securities offerings. There can be no assurance, however, that any such actions will be successful.

In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver has a borrowing base that is redetermined semi-annually. In connection with the closing of the Appalachian asset sale transaction on July 31, 2012, the borrowing base under the Revolver was decreased by $70 million to a level of $230 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. Our current business plans anticipate us borrowing amounts under the Revolver that are within the borrowing base limitations.

As of August 1, 2012, after repaying a portion of our outstanding Revolver balance with proceeds from the sale of our Appalachian assets, we had approximately $11 million of cash on hand and $128.3 million of unused borrowing capacity under the Revolver. The borrowing capacity is determined by reducing the borrowing base commitment of $230 million by remaining outstanding borrowings of $100 million and outstanding letters of credit of $1.7 million.

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



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three Months Ended June 30,	$	156,033	$	180,000	2.1547	%
Six Months Ended June 30,	$	132,758	$	180,000	2.1049	%

Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, we actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. During the first half of 2012, our commodity derivatives portfolio provided $13.7 million of cash inflows related to lower than anticipated prices received for our natural gas production and $0.2 million of cash outflows attributable to higher than anticipated prices received for our crude oil production.

In January 2012, we amended the Revolver to enhance our ability to hedge production. Previously, our hedging was limited to the lesser of certain fixed percentages of our reasonably anticipated production from proved developed reserves and total proved reserves. The amendment expands the potential volume subject to hedging to certain percentages of reasonably anticipated production from proved undeveloped reserves as well as proved developed reserves.

For the remainder of 2012, we have hedged approximately 32% of our estimated natural gas production, at a weighted average swap price of $5.24 per MMBtu. In addition, we have hedged approximately 67% of our estimated crude oil production for the remainder of 2012, at weighted average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel.

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Cash Flows

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



	Six Months Ended June 30,
	2012			2011			Variance
Cash flows from operating activities	$	115,725		$	63,759		$	51,966
Cash flows from investing activities
Capital expenditures - property and equipment	(188,236		)	(211,081		)	22,845
Proceeds from sales of property and equipment and other, net	707			796			(89		)
Net cash used in investing activities	(187,529		)	(210,285		)	22,756
Cash flows from financing activities
Dividends paid	(5,176		)	(5,156		)	(20		)
Proceeds from revolving credit facility borrowings, net	81,000			—			81,000
Proceeds from issuance of senior notes	—			300,000			(300,000		)
Repurchase of Convertible Notes	—			(232,963		)	232,963
Debt issuance costs paid	—			(6,559		)	6,559
Other, net	—			974			(974		)
Net cash provided by (used in) financing activities	75,824			56,296			19,528
Net decrease in cash and cash equivalents	$	4,020		$	(90,230	)	$	94,250

Cash Flows From Operating Activities

The following table summarizes the most significant variances in our cash flows from operating activities:



Cash flows from operating activities for the six months ended June 30, 2011	$	63,759
Variances due to:
Effect of higher operating margins, net of working capital changes	53,618
Higher settlements from commodity derivatives portfolio	2,668
Transaction costs paid in connection with extinguishment of debt in 2011	2,416
Higher interest payments, net of interest rate swap settlements	(6,951		)
Other, net	215
Cash flows from operating activities for the six months ended June 30, 2012	$	115,725

Due primarily to the realization of higher net margins on our expanding crude oil production, our cash flows from operating activities improved significantly during the 2012 period as compared to the 2011 period. During the 2012 period, we realized higher settlements from our commodity derivatives portfolio as compared to the 2011 period due primarily to lower natural gas prices partially offset by a lower overall hedged production volume. We paid higher amounts for interest during the 2012 period due to higher average outstanding debt balances. In addition, our sources from working capital were higher during the 2012 period due primarily to timing of collections and disbursements and lower compensation-related costs paid in the 2012 period. The 2011 period included transaction costs paid in connection with the repurchase of our Convertible Notes.

Cash Flows From Investing Activities

Capital expenditures were lower during the 2012 period due primarily to our focus on Eagle Ford Shale drilling. During the prior year period, we acquired significant acreage in the Eagle Ford Shale and had a more extensive capital program in the Mid-Continent region.

Proceeds from sales of non-core properties and other assets were received during both the 2012 and 2011 periods. The amounts received during the 2012 period are primarily attributable to the sale of our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania. Both periods include the receipt of insurance proceeds attributable to damages from a fire at one of our warehouse facilities in early 2011.

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



	Six Months Ended June 30,
	2012		2011
Oil and gas:
Development drilling	$	120,304	$	119,711
Exploration drilling	42,056		39,765
Seismic	320		6,137
Lease acquisitions, field projects and other	10,894		39,901
Pipeline and gathering facilities	8,349		3,571
	181,923		209,085
Other - Corporate	426		629
	$	182,349	$	209,714

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



	Six Months Ended June 30,
	2012			2011
Total capital program costs	$	182,349		$	209,714
Less:
Exploration expenses
Seismic	(320		)	(6,137		)
Other, primarily delay rentals	(501		)	(1,702		)
Transfers from tubular inventory and well materials	(10,775		)	(1,576		)
Changes in accrued capitalized costs	14,617			9,692
Add:
Tubular inventory and well materials purchased in advance of drilling	2,370			—
Capitalized interest	498			990
Other	(2		)	100
Total cash paid for capital expenditures	$	188,236		$	211,081

Cash Flows From Financing Activities

Cash provided by financing activities during the 2012 period included borrowings under the Revolver while activity during the 2011 period included the effect of issuing the 2019 Senior Notes offset by the repurchase of a substantial portion of the Convertible Notes. Both periods included dividend payments on common stock and the 2011 period includes proceeds received from the exercise of stock options by employees.

Financial Condition

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Credit Facility and Debt

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



	June 30, 2012			December 31, 2011
Revolving credit facility	$	180,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)	294,144			293,561
Senior notes due 2019	300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)	4,837			4,746
	778,981			697,307
Less: Current portion of long-term debt	(4,837		)	(4,746		)
	$	774,144		$	692,561

Revolving Credit Facility. 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, or Adjusted LIBOR, plus an applicable margin ranging from 1.500% to 2.500% or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are being charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity. As of June 30, 2012, the effective interest rate on the borrowings under the Revolver was 2.2500%.

The Revolver is guaranteed by Penn Virginia and all of our material subsidiaries, or 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.

2016 Senior Notes. The Senior Notes due 2016, or 2016 Senior Notes, bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

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

Convertible Notes. The Convertible Notes, which mature in November 2012, are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year.

The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.

In connection with a tender offer completed in April 2011, we repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, including a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded with the net proceeds of the 2019 Senior Notes offering. Subsequent to the tender offer, a total of $4.9 million aggregate principal amount of Convertible Notes remain outstanding. The remaining unamortized discount will be amortized through November 2012.

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Covenant Compliance

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


•	Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.


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

As of June 30, 2012 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 for the period ended June 30, 2012:



Description of Covenant	Required Covenant	Actual Results
Total debt to EBITDAX	< 4.5 to 1	3.1 to 1
Current ratio	> 1.0 to 1	2.4 to 1

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

Future Capital Needs and Commitments

In 2012, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $325 million. The capital expenditures have been and will continue to be funded primarily by operating cash flows, proceeds from sales of non-strategic assets and borrowing under the Revolver. We recently discontinued our common stock dividend which improves liquidity by increasing available cash flows by approximately $10 million per year. Other potential sources of additional liquidity include an increase in our Revolver borrowing base resulting from an increase in our Eagle Ford Shale proved reserves, third party joint ventures, additional non-strategic asset sales or securities offerings. There can be no assurance, however, that any such actions will be successful. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the availability of capital.

Based on expenditures to date and forecasted activity for the remainder of 2012, we expect to allocate capital expenditures as follows: Eagle Ford Shale (92%), Mid-Continent region (7%) and all other areas (1%). This allocation includes approximately 86% for development and exploratory drilling, 7% for leasehold acquisition and 7% for seismic and other projects. We anticipate that we will allocate substantially all of our capital expenditures to oil and NGL projects.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws which are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some

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form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of June 30, 2012, we had recorded asset retirement obligations of $6.4 million attributable to these activities. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011. The following development is discussed with respect to its applicability during the six months ended June 30, 2012 and future periods.

Share-Based Compensation

In February 2012, we granted performance-based restricted stock units, or PBRSUs, to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.

Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period based on the fair value derived from a Monte Carlo model and recognized based on the period of time that has elapsed during each of the individual performance periods. The Monte Carlo model is a binomial valuation model that requires significant judgment with respect to certain assumptions including volatility, dividends and other factors. Due primarily to the sensitivity of certain model assumptions as well as the inherent variability of modeling market-based performance over future periods, our compensation expense with respect to the PBRSUs can be volatile. As an illustration, the expense attributable to the PBRSUs during the three months ended June 30, 2012 was $0.6 million while the expense during the three months ended March 31, 2012 was less than $0.1 million.

New Accounting Standards

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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, changes in interest rates do not affect the amount of interest we pay on our fixed-rate debt instruments. However, changes in interest rates will affect the fair value of our long-term debt instruments. Our interest rate risk is attributable to our borrowings under the Revolver which is subject to variable interest rates. As of June 30, 2012, we had borrowings of $180 million outstanding under the Revolver at an effective interest rate of 2.2500%. Assuming a constant borrowing level of $180 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense of approximately $1.8 million on an annual basis.

Commodity Price Risk

We produce and sell natural gas, crude oil and NGLs. As a result, our financial results are affected when prices for these commodities fluctuate. Our price risk management programs permit the utilization of derivative financial instruments (such as collars, swaps and swaptions) to seek to mitigate the price risks associated with fluctuations in natural gas, crude oil and NGL 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 natural gas, crude oil and NGLs.

During the six months ended June 30, 2012, we reported net commodity derivative income of $43.8 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 natural gas, crude oil and NGL 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.

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The following table lists our commodity derivative positions and their fair values as of June 30, 2012:



		Average Volume Per Day	Weighted Average Price				Fair Value
	Instrument	Average Volume Per Day	Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)	($/MMBtu)
Third quarter 2012	Swaps	20,000	$	5.31			$	4,594	$	—
Fourth quarter 2012	Swaps	10,000	$	5.10			1,824		—
Crude Oil:		(barrels)	($/barrel)
Third quarter 2012	Collars	1,000	$	90.00	$	97.00	519		—
Fourth quarter 2012	Collars	1,000	$	90.00	$	97.00	512		—
First quarter 2013	Collars	1,000	$	90.00	$	100.00	518		—
Second quarter 2013	Collars	1,000	$	90.00	$	100.00	491		—
Third quarter 2013	Collars	1,000	$	90.00	$	100.00	503		—
Fourth quarter 2013	Collars	1,000	$	90.00	$	100.00	521		—
Third quarter 2012	Swaps	3,000	$	104.40			5,204		—
Fourth quarter 2012	Swaps	3,000	$	104.40			4,817		—
First quarter 2013	Swaps	2,250	$	103.51			3,108		—
Second quarter 2013	Swaps	2,250	$	103.51			3,004		—
Third quarter 2013	Swaps	1,500	$	102.77			1,916		—
Fourth quarter 2013	Swaps	1,500	$	102.77			1,940		—
First quarter 2014	Swaps	2,000	$	100.44			2,166		—
Second quarter 2014	Swaps	2,000	$	100.44			2,232		—
Third quarter 2014	Swaps	1,500	$	100.20			1,687		—
Fourth quarter 2014	Swaps	1,500	$	100.20			1,699		—
First quarter 2013	Swaption	1,100	$	100.00			—		290
Second quarter 2013	Swaption	1,000	$	100.00			—		241
Third quarter 2013	Swaption	900	$	100.00			—		180
Fourth quarter 2013	Swaption	750	$	100.00			—		117
First quarter 2014	Swaption	812	$	100.00			—		338
Second quarter 2014	Swaption	812	$	100.00			—		338
Third quarter 2014	Swaption	812	$	100.00			—		339
Fourth quarter 2014	Swaption	812	$	100.00			—		339
Settlements to be received in subsequent period							2,086		—

The following table illustrates the estimated impact on the fair values of our derivative instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This assumes that natural gas prices, crude oil 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 $1.00 per MMBtu of Natural Gas or $10.00 per Barrel of Crude Oil ($ in millions)
	Increase			Decrease
Effect on the fair value of natural gas derivatives	$	(2.1	)	$	2.0
Effect on the fair value of crude oil derivatives	$	(28.1	)	$	18.3
Effect on 2012 operating income, excluding natural gas derivatives	$	9.0		$	(9.0	)
Effect on 2012 operating income, excluding crude oil derivatives	$	11.0		$	(11.0	)

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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 Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2012. 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 Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2012, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 6 Exhibits



2.1	Purchase and Sale Agreement dated July 16, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on July 18, 2012).

2.1.1	Amendment and Supplement to Purchase and Sale Agreement, dated July 31, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on August 2, 2012).

3.1	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on May 7, 2012).

10.1	Revised Exhibit A to Penn Virginia Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K/A filed on April 3, 2012).

10.2	Penn Virgina Corporation 2011 Annual Incentive Cash Bonus and Long-Term Equity Compensation Guidelines (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on April 12, 2012).

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), 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

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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

Date: August 2, 2012	By:	/s/ Steven A. Hartman
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer

Date: August 2, 2012	By:	/s/ Joan C. Sonnen
		Joan C. Sonnen
		Vice President and Controller