10-Q 1 v308745_10q.htm FORM 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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 April 27, 2012, 45,827,010 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2012

Table of Contents

Item		Page
	Part I - Financial Information

1.	Financial Statements
	Condensed Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011	1
	Condensed Consolidated Statements of Comprehensive Income for the Three Months Ended March 31, 2012 and 2011	2
	Condensed Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011	3
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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	5
	5. Derivative Instruments	6
	6. Property and Equipment	8
	7. Long-Term Debt	8
	8. Additional Balance Sheet Detail	10
	9. Fair Value Measurements	10
	10. Commitments and Contingencies	12
	11. Shareholders’ Equity	13
	12. Share-Based Compensation	13
	13. Restructuring Activities	14
	14. Interest Expense	14
	15. Earnings per Share	15

Forward-Looking Statements		16

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	17

	Overview of Business	17
	Key Developments	18
	Results of Operations	19
	Liquidity and Capital Resources	25
	Environmental Matters	29
	Critical Accounting Estimates	30
	New Accounting Standards	30

3.	Quantitative and Qualitative Disclosures About Market Risk	31

4.	Controls and Procedures	33

	Part II - Other Information

6.	Exhibits	34

Signatures		35

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)

	Three Months Ended March 31,
	2012			2011
Revenues
Natural gas	$	14,886		$	41,189
Crude oil		58,723			16,583
Natural gas liquids (NGLs)		9,071			9,921
Gain on sales of property and equipment, net		756			480
Other		975			410
Total revenues		84,411			68,583

Operating expenses
Lease operating		9,143			10,277
Gathering, processing and transportation		4,154			4,028
Production and ad valorem taxes		3,580			5,064
General and administrative		12,141			13,352
Exploration		7,998			29,548
Depreciation, depletion and amortization		50,817			34,843
Total operating expenses		87,833			97,112

Operating loss		(3,422	)		(28,529	)

Other income (expense)
Interest expense		(14,774	)		(13,484	)
Derivatives		(305	)		1,328
Other		1			144
Loss before income taxes		(18,500	)		(40,541	)
Income tax benefit		6,601			14,201
Net loss	$	(11,899	)	$	(26,340	)

Loss per share:
Basic	$	(0.26	)	$	(0.58	)
Diluted	$	(0.26	)	$	(0.58	)

Weighted average shares outstanding, basic		45,945			45,687
Weighted average shares outstanding, diluted		45,945			45,687

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)

	Three Months Ended March 31,
	2012			2011
Net loss	$	(11,899	)	$	(26,340	)
Other comprehensive income (loss):
Change in pension and postretirement obligations, net of tax of $13 in 2012 and $18 in 2011		23			34
		23			34
Comprehensive loss	$	(11,876	)	$	(26,306	)

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)

	As of
	March 31,			December 31,
	2012			2011
Assets
Current assets
Cash and cash equivalents	$	1,936		$	7,512
Accounts receivable, net of allowance for doubtful accounts		71,383			72,432
Derivative assets		14,836			18,987
Income taxes receivable		31,164			31,465
Other current assets		9,227			14,950
Total current assets		128,546			145,346
Property and equipment, net (successful efforts method)		1,809,291			1,777,575
Derivative assets		1,167			-
Other assets		19,699			20,132
Total assets	$	1,958,703		$	1,943,053

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	103,773		$	94,504
Derivative liabilities		7,262			3,549
Deferred income taxes		3,808			3,808
Current portion of long-term debt		4,791			4,746
Total current liabilities		119,634			106,607
Other liabilities		16,073			15,887
Derivative liabilities		8,437			6,850
Deferred income taxes		268,250			274,839
Long-term debt		712,848			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 45,827,010 and 45,714,191 as of March 31, 2012 and December 31, 2011, respectively		271			270
Paid-in capital		691,745			690,131
Retained earnings		142,757			157,242
Deferred compensation obligation		3,660			3,620
Accumulated other comprehensive loss		(1,061	)		(1,084	)
Treasury stock – 232,708 and 223,886 shares of common stock, at cost, as of March 31, 2012 and December 31, 2011, respectively		(3,911	)		(3,870	)
Total shareholders’ equity		833,461			846,309
Total liabilities and shareholders’ equity	$	1,958,703		$	1,943,053

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended March 31,
	2012			2011
Cash flows from operating activities
Net loss	$	(11,899	)	$	(26,340	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		50,817			34,843
Derivative contracts:
Net losses (gains)		305			(1,328	)
Cash settlements		7,981			6,744
Deferred income tax benefit		(6,601	)		(14,201	)
Gain on sales of property and equipment, net		(756	)		(480	)
Non-cash exploration expense		8,171			26,999
Non-cash interest expense		1,015			3,272
Share-based compensation		1,615			1,796
Other, net		56			236
Changes in operating assets and liabilities, net		19,997			(2,105	)
Net cash provided by operating activities		70,701			29,436

Cash flows from investing activities
Capital expenditures - property and equipment		(94,469	)		(100,729	)
Proceeds from sales of property and equipment, net		778			360
Other, net		-			100
Net cash used in investing activities		(93,691	)		(100,269	)

Cash flows from financing activities
Dividends paid		(2,586	)		(2,576	)
Proceeds from revolving credit facility borrowings		23,000			-
Repayment of revolving credit facility borrowings		(3,000	)		-
Other, net		-			838
Net cash provided by (used in) financing activities		17,414			(1,738	)

Net decrease in cash and cash equivalents		(5,576	)		(72,571	)
Cash and cash equivalents - beginning of period		7,512			120,911
Cash and cash equivalents - end of period	$	1,936		$	48,340

Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	557		$	387
Income taxes (net of refunds received)	$	(301	)	$	(120	)

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

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended March 31, 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 three months ended March 31, 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 March 31, 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. Except for the redetermination of the borrowing base for our revolving credit facility (“Revolver”) described in Note 7, 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 an area of mutual interest in Lavaca County, Texas. Depending upon the future participation of other parties included in the joint venture, our minimum working interest is expected to be approximately 57%. 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 two successful exploratory wells on the acreage in the three months ended March 31, 2012.

Divestitures

Oil and Gas Properties

4. Accounts Receivable and Major Customers

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

	March 31,			December 31,
	2012			2011
Customers	$	48,695		$	49,763
Joint interest partners		22,844			22,755
Other		1,109			1,695
		72,648			74,213
Less: Allowance for doubtful accounts		(1,265	)		(1,781	)
	$	71,383		$	72,432

For the three months ended March 31, 2012 and 2011, five customers accounted for $55.7 million and $31.8 million, or approximately 67% and 47%, of our total consolidated product revenues. As of March 31, 2012 and December 31, 2011, $29.4 million and $36.0 million, or approximately 41% and 50%, 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, which are placed with financial institutions that we believe are acceptable credit risks, generally take the form of costless collars, swaps and swaptions. Our derivative instruments are not formally designated as hedges.

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 period. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position, and our own credit risk if the derivative is in a liability position.

The following table sets forth our commodity derivative positions as of March 31, 2012:

			Average
			Volume Per		Weighted Average Price				Fair Value
	Instrument		Day		Floor/Swap		Ceiling		Asset		Liability
Natural Gas:				(in MMBtu)		($/MMBtu)
Second quarter 2012		Swaps		20,000	$	5.31			$	5,667	$	-
Third quarter 2012		Swaps		20,000	$	5.31				5,234		-
Fourth quarter 2012		Swaps		10,000	$	5.10				2,042		-

Crude Oil:				(barrels)		($/barrel)
Second quarter 2012		Collars		1,000	$	90.00	$	97.00		-		677
Third quarter 2012		Collars		1,000	$	90.00	$	97.00		-		842
Fourth quarter 2012		Collars		1,000	$	90.00	$	97.00		-		904
First quarter 2013		Collars		1,000	$	90.00	$	100.00		-		710
Second quarter 2013		Collars		1,000	$	90.00	$	100.00		-		647
Third quarter 2013		Collars		1,000	$	90.00	$	100.00		-		573
Fourth quarter 2013		Collars		1,000	$	90.00	$	100.00		-		491
Second quarter 2012		Swaps		3,000	$	103.05				307		472
Third quarter 2012		Swaps		3,000	$	104.40				423		504
Fourth quarter 2012		Swaps		3,000	$	104.40				349		569
First Quarter 2013		Swaps		2,250	$	103.51				81		381
Second Quarter 2013		Swaps		2,250	$	103.51				123		239
Third Quarter 2013		Swaps		1,500	$	102.77				84		118
Fourth Quarter 2013		Swaps		1,500	$	102.77				175		73
First Quarter 2014		Swaps		2,000	$	100.44				22		53
Second Quarter 2014		Swaps		2,000	$	100.44				189		-
Third Quarter 2014		Swaps		1,500	$	100.20				265		-
Fourth Quarter 2014		Swaps		1,500	$	100.20				378		-
First quarter 2013		Swaption		1,100	$	100.00				-		1,195
Second quarter 2013		Swaption		1,000	$	100.00				-		1,013
Third quarter 2013		Swaption		900	$	100.00				-		831
Fourth quarter 2013		Swaption		750	$	100.00				-		620
First Quarter 2014		Swaption		812	$	100.00				-		725
Second Quarter 2014		Swaption		812	$	100.00				-		725
Third Quarter 2014		Swaption		812	$	100.00				-		725
Fourth Quarter 2014		Swaption		812	$	100.00				-		725
Settlements to be paid in subsequent period										-		624

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”).

The following table sets forth the terms and liability position of our interest rate swap as of the dates presented:

	Notional		Swap Interest Rates ¹					March 31,			December 31,
Term	Amount		Pay		Receive			2012			2011
Through April 15, 2019	$	100,000		LIBOR + 5.68%		7.250	%	$	(599	)	$	-

¹ References to LIBOR represent the one-month rate.

During the three months ended March 31, 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). During August 2011, we terminated this agreement and received $2.9 million in cash proceeds.

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 March 31,
	2012			2011
Impact by contract type:
Commodity contracts	$	294		$	1,308
Interest rate contracts		(599	)		20
	$	(305	)	$	1,328
Realized and unrealized impact:
Cash received (paid) for:
Commodity contract settlements	$	7,981		$	6,744
Interest rate contract settlements		-			-
		7,981			6,744
Unrealized gains (losses) attributable to:
Commodity contracts		(7,687	)		(5,436	)
Interest rate contracts		(599	)		20
		(8,286	)		(5,416	)
	$	(305	)	$	1,328

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
		March 31, 2012				December 31, 2011
			Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location		Assets		Liabilities		Assets		Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	14,492	$	7,262	$	18,987	$	3,549
Interest rate contracts	Derivative assets/liabilities - current		344		-		-		-
			14,836		7,262		18,987		3,549
Commodity contracts	Derivative assets/liabilities - noncurrent		1,167		7,494		-		6,850
Interest rate contracts	Derivative assets/liabilities - noncurrent		-		943		-		-
			1,167		8,437		-		6,850
		$	16,003	$	15,699	$	18,987	$	10,399

As of March 31, 2012, we reported a commodity derivative asset of $15.7 million. The contracts associated with this position are with four counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

6. Property and Equipment

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

	March 31,			December 31,
	2012			2011
Oil and gas properties:
Proved	$	2,325,116		$	2,239,186
Unproved		112,809			120,288
Total oil and gas properties		2,437,925			2,359,474
Other property and equipment		147,252			143,285
Total property and equipment		2,585,177			2,502,759
Accumulated depreciation, depletion and amortization		(775,886	)		(725,184	)
	$	1,809,291		$	1,777,575

7. Long-Term Debt

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

	March 31,			December 31,
	2012			2011
Revolving credit facility	$	119,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)		293,848			293,561
Senior notes due 2019		300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)		4,791			4,746
		717,639			697,307
Less: Current portion of long-term debt		(4,791	)		(4,746	)
	$	712,848		$	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. In April 2012, the bank syndicate supporting the Revolver completed its redetermination and established a borrowing base of $300 million. Accordingly, the minimum revolving commitment remained unchanged. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. We had letters of credit of $1.4 million outstanding as of March 31, 2012. As of March 31, 2012, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $179.6 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 March 31, 2012, the effective interest rate on the borrowings under the Revolver was 2.034%.

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 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 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 beginning 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 beginning 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 which is included in 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 following table summarizes the carrying amount of the components of the Convertible Notes as of the dates presented:

	March 31,			December 31,
	2012			2011
Principal	$	4,915		$	4,915
Unamortized discount		(124	)		(169	)
Net carrying amount of liability component	$	4,791		$	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 March 31,
	2012		2011
Contractual interest expense	$	55	$	2,588
Accretion on original issue discount		45		1,947
Amortization of debt issuance costs		7		334
	$	107	$	4,869

8. Additional Balance Sheet Detail

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

	March 31,		December 31,
	2012		2011
Other current assets:
Tubular inventory and well materials	$	8,170	$	14,251
Prepaid expenses		1,057		699
	$	9,227	$	14,950
Other assets:
Debt issuance costs	$	16,311	$	16,993
Assets of supplemental employee retirement plan ("SERP")		3,339		3,088
Other		49		51
	$	19,699	$	20,132
Accounts payable and accrued liabilities:
Trade accounts payable	$	41,162	$	30,186
Drilling costs		20,881		30,948
Royalties		15,035		15,235
Production and franchise taxes		2,695		3,495
Compensation		2,668		5,186
Interest		19,423		5,964
Other		1,909		3,490
	$	103,773	$	94,504
Other liabilities:
Asset retirement obligations	$	6,392	$	6,283
Defined benefit pension obligations		1,728		1,763
Postretirement health care benefit obligations		3,018		3,022
Deferred compensation - SERP obligation and other		3,413		3,172
Other		1,522		1,647
	$	16,073	$	15,887

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 March 31, 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:

	March 31, 2012				December 31, 2011
	Fair		Carrying		Fair		Carrying
	Value		Value		Value		Value
Senior Notes due 2016	$	300,000	$	293,848	$	319,500	$	293,561
Senior Notes due 2019		256,950		300,000		280,500		300,000
Convertible Notes		4,915		4,791		4,925		4,746
	$	561,865	$	598,639	$	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 March 31, 2012
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	14,492		$	-		$	14,492		$	-
Commodity derivative assets - noncurrent		1,167			-			1,167			-
Interest rate swap assets - current		344						344
Assets of SERP		3,339			3,339			-			-

Liabilities:
Commodity derivative liabilities - current		(7,262	)		-			(7,262	)		-
Commodity derivative liabilities - noncurrent		(7,494	)		-			(7,494	)		-
Interest rate swap liabilities - noncurrent		(943	)					(943	)
Deferred compensation - SERP obligation and other		(3,409	)		(3,409	)		-			-
	$	234		$	(70	)	$	304		$	-

	As of December 31, 2011
	Fair Value			Fair Value Measurement Classification
Description	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		$	-

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three months ended March 31, 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.

•

Interest rate swaps: We determine the fair values of our interest rate swaps using an income approach valuation technique that connects future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. 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, 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.

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 March 31, 2012. In addition, as of March 31, 2012, we have an ARO liability of approximately $6.4 million attributable to the plugging of abandoned wells.

11. Shareholders’ Equity

The following table summarizes the components of our shareholders’ equity and the changes therein as of and for the three months ended March 31, 2012 and 2011:

	Balance as of						Dividends Paid						Balance as of
	December 31,						($0.05625			All Other			March 31,
	2011			Net Loss			per share)			Changes			2012
Common stock	$	270		$	-		$	-		$	1		$	271
Paid-in capital		690,131			-			-			1,614			691,745
Retained earnings		157,242			(11,899	)		(2,586	)		-			142,757
Deferred compensation obligation		3,620			-			-			40			3,660
Accumulated other comprehensive loss		(1,084	)		-			-			23			(1,061	)
Treasury stock		(3,870	)		-			-			(41	)		(3,911	)
Total shareholders' equity	$	846,309		$	(11,899	)	$	(2,586	)	$	1,637		$	833,461

	Balance as of						Dividends Paid						Balance as of
	December 31,						($0.05625			All Other			March 31,
	2010			Net Loss			per share)			Changes			2011
Common stock	$	267		$	-		$	-		$	1		$	268
Paid-in capital		680,981			-			-			3,009			683,990
Retained earnings		300,473			(26,340	)		(2,576	)		-			271,557
Deferred compensation obligation		2,743			-			-			143			2,886
Accumulated other comprehensive loss		(938	)		-			-			34			(904	)
Treasury stock		(3,250	)		-			-			(45	)		(3,295	)
Total shareholders' equity	$	980,276		$	(26,340	)	$	(2,576	)	$	3,142		$	954,502

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 employees. 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.

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

	Three Months Ended March 31,
	2012		2011
Equity-classified awards:
Stock option plans	$	1,208	$	1,408
Common, deferred, restricted and time-based restricted unit plans		407		388
		1,615		1,796
Liability-classified awards		72		-
	$	1,687	$	1,796

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 three months ended March 31, 2012 that were attributable to this restructuring included cash payments and accretion of the long-term lease obligation and the cash payment of termination benefits accrued during 2011. Activities recorded during the three months ended March 31, 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 three months ended March 31:

	2012			2011
Balance at beginning of period	$	576		$	64
Employee, office and other costs accrued		(3	)		18
Cash payments		(98	)		(82	)
Balance at end of period	$	475		$	-

14. Interest Expense

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

	Three Months Ended March 31,
	2012			2011
Interest on borrowings and related fees	$	14,017		$	10,747
Accretion on original issue discount		333			2,205
Amortization of debt issuance costs		682			1,067
Capitalized interest		(258	)		(535	)
	$	14,774		$	13,484

15. Earnings per Share

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

	Three Months Ended March 31,
	2012			2011
Net loss	$	(11,899	)	$	(26,340	)

Weighted-average shares, basic		45,945			45,687
Effect of dilutive securities ¹		-			-
Weighted-average shares, diluted		45,945			45,687

¹For the three months ended March 31, 2012 and 2011, an amount less than 0.1 million and 0.1 million 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.

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 natural gas, natural gas liquids and oil;

•

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 natural gas, natural gas liquids and oil;

•

reductions in the borrowing base under our revolving credit facility (“Revolver”);

•

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

•

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

•

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

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. Our current operations include primarily the drilling of unconventional development wells and exploring for primarily unconventional reserves.

We are currently focused primarily on the Eagle Ford Shale in South Texas. We also pursue selected 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 March 31,
	2012			2011
Total production (MMcfe)		10,874			12,171
Daily production (MMcfe per day)		119.5			135.2
Daily gas production (MMcf per day)		69.2			108.1
Daily oil and NGL production (Bbl per day)		8,388			4,529

Product revenues, as reported	$	82,680		$	67,693
Product revenues, as adjusted for derivatives	$	90,661		$	74,437

Operating loss	$	(3,422	)	$	(28,529	)
Interest expense	$	14,774		$	13,484

Cash provided by operating activities	$	70,701		$	29,436
Cash paid for capital expenditures	$	94,469		$	100,729

Cash and cash equivalents at end of period	$	1,936		$	48,340
Debt outstanding, net of discounts, at end of period	$	717,639		$	508,741
Credit available under revolving credit facility at end of period ¹	$	179,600		$	210,056

Net development wells drilled		7.5			2.4
Net exploratory wells drilled		1.9			5.3

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

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) shifting the focus of our production from natural gas to crude oil and natural gas liquids, or NGLs, and (iii) hedging a portion of our crude oil production for the calendar years 2012 through 2014 to the levels permitted by the revolving credit agreement, or Revolver, and our internal policies.

Drilling Results and Future Development

During the three months ended March 31, 2012, we drilled a total of 11 gross (9.4 net) wells, including nine gross (7.5 net) development wells and two gross (1.9 net) exploratory wells in the Eagle Ford Shale.

We currently have two rigs drilling in the Eagle Ford Shale. We have drilled a total of 47 wells since we began drilling operations in this play during the first half of 2011. Of the total wells drilled, 44 (36.6 net) wells are producing, one is waiting on completion and two are in progress as of April 30, 2012. The average peak gross production rate per well for 40 of these wells which had full-length laterals was approximately 1,000 barrels of oil equivalent per day, or BOEPD. Our Eagle Ford Shale production was approximately 9,200 (5,800 net) BOEPD at the end of April 2012, with oil comprising 88 percent, NGLs comprising six percent and natural gas comprising approximately six percent. We have allocated approximately 89 percent of our capital expenditures during 2012 for activities in the Eagle Ford Shale.

Included in the totals presented above for the Eagle Ford Shale are our first two (1.9 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. Depending upon the future participation of other parties included in the joint venture, our minimum working interest is expected to be approximately 57%. 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.

Production Focus

During the past two years, we have made significant investments in higher rate-of-return projects in economically attractive oil and NGL-rich areas, primarily in the Eagle Ford Shale in South Texas. Accordingly, our production profile continues to experience a transformational shift from natural gas to oil and liquids. Approximately 42% of total production on an equivalent basis in the three months ended March 31, 2012 was attributable to oil and NGLs, an increase of approximately 87% over the prior year period. This also represents a sequential increase of approximately 15% over the three months ended December 31, 2011.

The proportion of total product revenues attributable to oil and NGLs was 82% for the three months ended March 31, 2012. This represents an increase of approximately 156% from the corresponding prior year period and approximately 26% from the three months ended December 31, 2011.

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 March 31, 2012, we have hedged the maximum volume of oil production as permitted under the terms of the Revolver and by our internal policies for calendar years 2012 through 2014. For the remainder of 2012, we have hedged approximately 70% of our estimated crude oil production at weighted-average floor/swap and ceiling prices of between $100.46 and $102.21 per barrel. For 2013, we have approximately 40% of our estimated production hedged at weighted-average floor/swap and ceiling prices of between $98.61 and $102.09 per barrel. For 2014, we have approximately 20% of our estimated production hedged at a weighted-average swap price of $100.33 per barrel. Our natural gas hedges represent approximately 25% of our estimated production for the balance of the year at a weighted-average swap price of $5.26 per MMBtu. At this time, we have no hedges in place for our estimated natural gas production beyond 2012.

Results of Operations

Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

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

	Three Months Ended March 31,						Favorable
	2012			2011			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		6,294			9,726			(3,432	)		(35	)%
Crude oil (MBbl)		549			188			361			192	%
NGLs (MBbl)		215			220			(5	)		(2	)%
Total production (MMcfe)		10,874			12,171			(1,297	)		(11	)%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	2.37		$	4.23		$	(1.86	)		(44	)%
Crude oil ($/Bbl)		107.05			88.37			18.68			21	%
NGLs ($/Bbl)		42.24			45.11			(2.87	)		(6	)%
Total ($/Mcfe)	$	7.60		$	5.56		$	2.04			37	%

Revenues
Natural gas	$	14,886		$	41,189		$	(26,303	)		(64	)%
Crude oil		58,723			16,583			42,140			254	%
NGLs		9,071			9,921			(850	)		(9	)%
Total product revenues		82,680			67,693			14,987			22	%
Gain on sales of property and equipment		756			480			276			58	%
Other income		975			410			565			138	%
Total revenues		84,411			68,583			15,828			23	%

Operating expenses
Lease operating		9,143			10,277			1,134			11	%
Gathering, processing and transportation		4,154			4,028			(126	)		(3	)%
Production and ad valorem taxes		3,580			5,064			1,484			29	%
General and administrative		12,141			13,352			1,211			9	%
Exploration		7,998			29,548			21,550			73	%
Depreciation, depletion and amortization		50,817			34,843			(15,974	)		(46	)%
Total operating expenses		87,833			97,112			9,279			10	%

Operating loss		(3,422	)		(28,529	)		25,107			88	%
Other income (expense)
Interest expense		(14,774	)		(13,484	)		(1,290	)		(10	)%
Derivatives		(305	)		1,328			(1,633	)		(123	)%
Other		1			144			(143	)		(99	)%
Loss before income taxes		(18,500	)		(40,541	)		22,041			54	%
Income tax benefit		6,601			14,201			(7,600	)		(54	)%
Net loss	$	(11,899	)	$	(26,340	)	$	14,441			55	%

NM - Not meaningful

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 March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)			% Change
	(MMcf)							(MMcf per day)
Texas		1,830		2,766		(936	)		20.1		30.7		(10.6	)		(35	)%
Appalachia		2,062		2,360		(298	)		22.7		26.2		(3.6	)		(14	)%
Mid-Continent		1,108		2,771		(1,662	)		12.2		30.8		(18.6	)		(60	)%
Mississippi		1,293		1,829		(536	)		14.2		20.3		(6.1	)		(30	)%
		6,294		9,726		(3,432	)		69.2		108.1		(38.9	)		(36	)%

Crude oil	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)			% Change
	(MBbl)							(MBbl per day)
Texas		479.2		57.0		422.3			5.27		0.63		4.63			732	%
Appalachia		0.2		0.5		(0.2	)		0.00		0.01		(0.00	)		(47	)%
Mid-Continent		65.1		125.1		(60.0	)		0.72		1.39		(0.67	)		(49	)%
Mississippi		4.0		5.2		(1.2	)		0.04		0.06		(0.01	)		(23	)%
		548.6		187.7		360.9			6.03		2.09		3.94			189	%

NGLs	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)			% Change
	(MBbl)							(MBbl per day)
Texas		106.3		119.6		(13.3	)		1.17		1.33		(0.16	)		(12	)%
Appalachia		0.2		0.2		(0.0	)		0.00		0.00		(0.00	)		(20	)%
Mid-Continent		108.3		100.1		8.2			1.19		1.11		0.08			7	%
		214.8		219.9		(5.1	)		2.36		2.44		(0.08	)		(3	)%

Combined total	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
Texas		5,344		3,826		1,518			58.7		42.5		16.2			38	%
Appalachia		2,065		2,364		(299	)		22.7		26.3		(3.6	)		(14	)%
Mid-Continent		2,148		4,121		(1,973	)		23.6		45.8		(22.2	)		(48	)%
Mississippi		1,317		1,860		(543	)		14.5		20.7		(6.2	)		(30	)%
		10,874		12,171		(1,297	)		119.5		135.2		(15.7	)		(12	)%

The decline in total production during the first three months of 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 1.1 Bcfe. 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 42% of total production on an equivalent basis in the three months ended March 31, 2012 was attributable to oil and NGLs, an 87% increase over the prior year period. The shift in production mix reflects our focus on emerging oil and liquids-rich plays in the Eagle Ford Shale in Texas and the Mid-Continent region. During the quarter ended March 31, 2012, our Eagle Ford Shale production represented 30% of our total production. We had no significant production from this play during the first quarter of 2011.

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 March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcf)
Texas	$	4,233	$	10,638	$	(6,405	)	$	2.31	$	3.85	$	(1.54	)
Appalachia		5,423		9,776		(4,353	)		2.63		4.14		(1.51	)
Mid-Continent		1,535		13,063		(11,528	)		1.39		4.71		(3.32	)
Mississippi		3,695		7,712		(4,017	)		2.86		4.22		(1.36	)
	$	14,886	$	41,189	$	(26,303	)	$	2.37	$	4.23	$	(1.86	)

Crude oil	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Bbl)
Texas	$	51,789	$	5,076	$	46,713		$	108.06	$	89.10	$	18.96
Appalachia		22		34		(12	)		91.67		75.56		16.11
Mid-Continent		6,464		10,985		(4,521	)		99.33		87.84		11.49
Mississippi		448		488		(40	)		111.44		94.12		17.32
	$	58,723	$	16,583	$	42,140		$	107.05	$	88.37	$	18.68

NGLs	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Bbl)
Texas	$	4,775	$	5,352	$	(577	)	$	44.90	$	44.74	$	0.16
Appalachia		11		10		1			60.11		44.25		15.86
Mid-Continent		4,285		4,559		(274	)		39.58		45.56		(5.98	)
	$	9,071	$	9,921	$	(850	)	$	42.24	$	45.11	$	(2.87	)

Combined total	Three Months Ended March 31,				Favorable			Three Months Ended March 31,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcfe)
Texas	$	60,797	$	21,066	$	39,731		$	11.38	$	5.51	$	5.87
Appalachia		5,456		9,820		(4,364	)		2.64		4.15		(1.51	)
Mid-Continent		12,284		28,607		(16,323	)		5.72		6.94		(1.22	)
Mississippi		4,143		8,200		(4,057	)		3.14		4.41		(1.27	)
	$	82,680	$	67,693	$	14,987		$	7.60	$	5.56	$	2.04

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 volume and prices. The following table provides an analysis of the change in our revenues for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011:

	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(14,533	)	$	(11,770	)	$	(26,303	)
Crude oil		31,895			10,245			42,140
NGLs		(232	)		(618	)		(850	)
	$	17,130		$	(2,143	)	$	14,987

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 March 31, 2012 and 2011, we received $8.0 million and $6.7 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 March 31,						Favorable
	2012			2011			(Unfavorable)			% Change
Natural gas revenues as reported	$	14,886		$	41,189		$	(26,303	)		(64	)%
Cash settlements on natural gas derivatives, net		8,088			6,969			1,119			16	%
Natural gas revenues adjusted for derivatives	$	22,974		$	48,158		$	(25,184	)		(52	)%

Natural gas prices per Mcf, as reported	$	2.37		$	4.23		$	(1.86	)		(44	)%
Cash settlements on natural gas derivatives per Mcf		1.28			0.72			0.56			79	%
Natural gas prices per Mcf adjusted for derivatives	$	3.65		$	4.95		$	(1.30	)		(26	)%

Crude oil revenues as reported	$	58,723		$	16,583		$	42,140			254	%
Cash settlements on crude oil derivatives, net		(107	)		(225	)		118			52	%
Crude oil revenues adjusted for derivatives	$	58,616		$	16,358		$	42,258			258	%

Crude oil prices per Bbl, as reported	$	107.05		$	88.37		$	18.68			21	%
Cash settlements on crude oil derivatives per Bbl		(0.20	)		(1.20	)		1.00			84	%
Crude oil prices per Bbl adjusted for derivatives	$	106.85		$	87.17		$	19.68			23	%

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 quarter ended March 31, 2012 due primarily to higher gathering, transportation and compression fees partially offset by lower salt water disposal fees.

Operating Expenses

As discussed individually below, we experienced an absolute decrease in several operating expenses. However, due primarily to declining natural gas production, certain expenses have 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 March 31,				Favorable
	2012		2011		(Unfavorable)			% Change
Lease operating	$	0.84	$	0.84	$	0.00			0	%
Gathering, processing and transportation		0.38		0.33		(0.05	)		(15	)%
Production and ad valorem taxes		0.33		0.42		0.09			21	%
General and administrative excluding share-based compensation and restructuring charges		0.97		0.95		(0.02	)		(2	)%
General and administrative		1.12		1.10		(0.02	)		(2	)%
Depreciation, depletion and amortization		4.67		2.86		(1.81	)		(63	)%

Lease Operating

Lease operating expense decreased on an absolute basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs following the rationalization of compression assets that was implemented during the latter half of 2011. Certain expense decreases were also attributable to the sale of our Arkoma Basin properties. Cost decreases were partially offset by higher water disposal, 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 to lower natural gas prices and lower severance tax rates for certain wells in Texas and Oklahoma. As a percentage of product revenue, production and ad valorem taxes decreased to 4.3% during the 2012 period from 7.5% during 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 March 31,				Favorable
	2012		2011		(Unfavorable)		% Change
Recurring general and administrative expenses	$	10,526	$	11,538	$	1,012		9	%
Share-based compensation		1,615		1,796		181		10	%
Restructuring expenses		-		18		18		100	%
	$	12,141	$	13,352	$	1,211		9	%

Recurring general and administrative expenses decreased due to reduced headcount and lower support costs primarily from restructuring actions taken during 2011. Share-based compensation charges decreased during the 2012 period due primarily to a lower number of awards granted.

Exploration

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

	Three Months Ended March 31,					Favorable
	2012			2011		(Unfavorable)		% Change
Unproved leasehold amortization	$	8,171		$	10,591	$	2,420		23	%
Dry hole costs		-			16,408		16,408		100	%
Geological and geophysical costs		(423	)		1,835		2,258		123	%
Other, primarily delay rentals		250			714		464		65	%
	$	7,998		$	29,548	$	21,550		73	%

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 quarter of 2012. The prior year period included dry hole costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, other exploration costs decreased during the 2012 period as our efforts are more concentrated on the Eagle Ford Shale exploration program while the prior year period included multiple exploratory prospect activities. In addition, the 2012 period includes a recoupment of amounts expended in prior periods.

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 March 31,				Favorable
	2012		2011		(Unfavorable)			% Change
Depletion	$	49,711	$	33,443	$	(16,268	)		(49	)%
Depreciation - Oil and gas operations		578		618		40			6	%
Depreciation - Corporate		413		652		239			37	%
Amortization		115		130		15			12	%
	$	50,817	$	34,843	$	(15,974	)		(46	)%

	DD&A Variance Due to
	Production		Rates			Total
Three months ended March 31, 2012 compared to 2011	$	3,713	$	(19,687	)	$	(15,974	)

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 $4.57 per Mcfe for the 2012 period from $2.75 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.

Interest Expense

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

	Three Months Ended March 31,						Favorable
	2012			2011			(Unfavorable)			% Change
Interest on borrowings and related fees	$	14,017		$	10,747		$	(3,270	)		(30	)%
Accretion of original issue discount		333			2,205			1,872			85	%
Amortization of debt issuance costs		682			1,067			385			36	%
Capitalized interest		(258	)		(535	)		(277	)		(52	)%
	$	14,774		$	13,484		$	(1,290	)		(10	)%

The issuance of the 7.25% Senior Notes due 2019, or 2019 Senior Notes, and borrowings under the Revolver, offset by the repurchase of approximately 98% of the outstanding 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes, with an effective interest rate at 8.5%, resulted in an approximate $199 million higher weighted-average balance of debt outstanding during the 2012 period as 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.

Derivatives

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

	Three Months Ended March 31,						Favorable
	2012			2011			(Unfavorable)			% Change
Oil and gas derivative unrealized loss	$	(7,687	)	$	(5,436	)	$	(2,251	)		41	%
Oil and gas derivative realized gain		7,981			6,744			1,237			18	%
Interest rate swap unrealized gain (loss)		(599	)		20			(619	)		NM
	$	(305	)	$	1,328		$	(1,633	)		(123	)%

We received cash settlements of $8.0 million during the three months ended March 31, 2012 and $6.7 million during the comparable period in 2011.

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 three months ended March 31, 2012 was 35.7% compared to 35.0% for the 2011 period. Due to operating losses incurred, we recognized income tax benefits during both periods.

Liquidity and Capital Resources

Sources of Liquidity

We are currently meeting our capital expenditures and working capital funding requirements with a combination of operating cash flows and borrowings under the Revolver. We have no material debt maturities until 2016. Our business strategy for 2012 requires capital expenditures in excess of our anticipated 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 2012 capital program with operating cash flows and borrowings under the Revolver. We expect to supplement these sources of liquidity with proceeds from sales of non-strategic assets. There can be no assurance, however, that such sales will be successful, in which case we could reduce our 2012 planned capital expenditures.

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 April 2012, the bank syndicate supporting the Revolver completed its redetermination and established a borrowing base of $300 million. Accordingly, the minimum revolving commitment remained unchanged. 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 current commitment level of $300 million.

As of March 31, 2012, we had $1.9 million of cash on hand and $179.6 million of unused borrowing capacity under the Revolver. The borrowing capacity is determined by reducing the revolving commitment of $300 million by outstanding borrowings of $119.0 million and outstanding letters of credit of $1.4 million.

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

	Borrowings Outstanding
	Weighted-				Weighted-
	Average		Maximum		Average Rate
Three months ended March 31, 2012	$	109,484	$	119,000		2.0340	%

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 quarter of 2012, our commodity derivatives portfolio provided $8.1 million of cash inflows related to lower than anticipated prices received for our natural gas production and $0.1 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 25% of our estimated natural gas production, at a weighted average swap price of $5.26 per MMBtu. In addition, we have hedged approximately 70% of our estimated crude oil production for the remainder of 2012, at weighted average floor/swap and ceiling prices of between $100.46 and $102.21 per barrel.

Cash Flows

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

	Three Months Ended March 31,
	2012			2011			Variance
Cash flows from operating activities	$	70,701		$	29,436		$	41,265
Cash flows from investing activities
Capital expenditures - property and equipment		(94,469	)		(100,729	)		6,260
Proceeds from sales of property and equipment and other, net		778			460			318
Net cash used in investing activities		(93,691	)		(100,269	)		6,578
Cash flows from financing activities
Dividends paid		(2,586	)		(2,576	)		(10	)
Proceeds from revolving credit facility borrowings, net		20,000			-			20,000
Other, net		-			838			(838	)
Net cash provided by (used in) financing activities		17,414			(1,738	)		19,152
Net decrease in cash and cash equivalents	$	(5,576	)	$	(72,571	)	$	66,995

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 three months ended March 31, 2011	$	29,436
Variances due to:
Effect of higher operating margins, net of working capital changes		40,033
Higher settlements from commodity derivatives portfolio		1,237
Other (Interest, income taxes and restructuring payments)		(5	)
Cash flows from operating activities for the three months ended March 31, 2012	$	70,701

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. In addition, our utilization of working capital was lower during the 2012 period due primarily to timing of disbursements and lower compensation-related costs paid in the 2012 period.

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 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.

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 both the Eagle Ford Shale as well as certain exploratory prospects in the Mid-Continent region. During the prior year period, we also had an active exploratory drilling 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.

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

	Three Months Ended March 31,
	2012			2011
Oil and gas:
Development drilling	$	61,440		$	36,775
Exploration drilling		21,152			26,894
Seismic		(423	)		1,835
Lease acquisitions, field projects and other		4,344			38,409
Pipeline and gathering facilities		3,901			374
		90,414			104,287
Other - Corporate		66			336
	$	90,480		$	104,623

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:

	Three Months Ended March 31,
	2012			2011
Total capital program costs	$	90,480		$	104,623
Less:
Exploration expenses
Seismic		423			(1,835	)
Other, primarily delay rentals		(199	)		(716	)
Transfers from tubular inventory and well materials		(6,081	)		(608	)
Changes in accrued capitalized costs		9,588			(1,270	)
Add:
Capitalized interest		258			535
Total cash paid for capital expenditures	$	94,469		$	100,729

Cash Flows From Financing Activities

Cash provided by financing activities during the 2012 period included borrowings under the Revolver partially offset by dividends paid on our common stock while activity during the prior year period included dividend payments partially offset by the proceeds received from the exercise of stock options by employees.

Financial Condition

Credit Facility and Debt

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

	March 31,			December 31,
	2012			2011
Revolving credit facility	$	119,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)		293,848			293,561
Senior notes due 2019		300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915 and $230,000)		4,791			4,746
		717,639			697,307
Less: Current portion of long-term debt		(4,791	)		(4,746	)
	$	712,848		$	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 March 31, 2012, the effective interest rate on the borrowings under the Revolver was 2.034%.

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.

Under the Revolver, we are permitted under certain conditions to repurchase up to $100 million of the 2016 Senior Notes until August 2012. Accordingly, we may, from time to time, seek to repurchase the 2016 Senior Notes through open market purchases or privately negotiated transactions. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

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, 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 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.

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 March 31, 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 March 31, 2012:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.5 to 1	3.0 to 1
Current ratio	> 1.0 to 1	2.6 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 and borrowing under the Revolver. We expect to supplement these sources of liquidity with proceeds from sales of non-strategic assets. There can be no assurance, however, that such sales will be successful, in which case we could reduce our 2012 planned capital expenditures. 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 (89%), Mid-Continent region (4%) and all other areas (7%). 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 form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of March 31, 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 three months ended March 31, 2012 and future periods.

Share-Based Compensation

In February 2012, we granted performance-based restricted stock units, or PBRSUs, to certain executive employees. 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 is expected to be volatile. Due to the relatively brief period during which the PBRSUs were outstanding during the three months ended March 31, 2012, however, the related compensation expense was not significant in the current period.

New Accounting Standards

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 March 31, 2012, we had borrowings of $119 million outstanding under the Revolver at an effective interest rate of 2.034%. Assuming a constant borrowing level of $119 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 $1.2 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 three months ended March 31, 2012, we reported net commodity derivative income of $0.3 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in 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.

The following table lists our commodity derivative positions and their fair values as of March 31, 2012:

		Average
		Volume Per		Weighted Average Price				Fair Value
	Instrument	Day		Floor/Swap		Ceiling		Asset		Liability
Natural Gas:			(in MMBtu)		($/MMBtu)
Second quarter 2012	Swaps		20,000	$	5.31			$	5,667	$	-
Third quarter 2012	Swaps		20,000	$	5.31				5,234		-
Fourth quarter 2012	Swaps		10,000	$	5.10				2,042		-

Crude Oil:			(barrels)		($/barrel)
Second quarter 2012	Collars		1,000	$	90.00	$	97.00		-		677
Third quarter 2012	Collars		1,000	$	90.00	$	97.00		-		842
Fourth quarter 2012	Collars		1,000	$	90.00	$	97.00		-		904
First quarter 2013	Collars		1,000	$	90.00	$	100.00		-		710
Second quarter 2013	Collars		1,000	$	90.00	$	100.00		-		647
Third quarter 2013	Collars		1,000	$	90.00	$	100.00		-		573
Fourth quarter 2013	Collars		1,000	$	90.00	$	100.00		-		491
Second quarter 2012	Swaps		3,000	$	103.05				307		472
Third quarter 2012	Swaps		3,000	$	104.40				423		504
Fourth quarter 2012	Swaps		3,000	$	104.40				349		569
First Quarter 2013	Swaps		2,250	$	103.51				81		381
Second Quarter 2013	Swaps		2,250	$	103.51				123		239
Third Quarter 2013	Swaps		1,500	$	102.77				84		118
Fourth Quarter 2013	Swaps		1,500	$	102.77				175		73
First Quarter 2014	Swaps		2,000	$	100.44				22		53
Second Quarter 2014	Swaps		2,000	$	100.44				189		-
Third Quarter 2014	Swaps		1,500	$	100.20				265		-
Fourth Quarter 2014	Swaps		1,500	$	100.20				378		-
First quarter 2013	Swaption		1,100	$	100.00				-		1,195
Second quarter 2013	Swaption		1,000	$	100.00				-		1,013
Third quarter 2013	Swaption		900	$	100.00				-		831
Fourth quarter 2013	Swaption		750	$	100.00				-		620
First Quarter 2014	Swaption		812	$	100.00				-		725
Second Quarter 2014	Swaption		812	$	100.00				-		725
Third Quarter 2014	Swaption		812	$	100.00				-		725
Fourth Quarter 2014	Swaption		812	$	100.00				-		725
Settlements to be paid in subsequent period									-		624

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	$	(4.0	)	$	4.0
Effect on the fair value of crude oil derivatives	$	(31.8	)	$	30.3

Effect on 2012 operating income, excluding natural gas derivatives	$	15.4		$	(15.4	)
Effect on 2012 operating income, excluding crude oil derivatives	$	17.1		$	(17.1	)

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 March 31, 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 March 31, 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.

PART II. OTHER INFORMATION

Item 6 Exhibits

10.1		First Amendment to Amended and Restated Credit Agreement dated January 11, 2012 among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on January 17, 2012).

10.2		Form of Agreement for Performance Based Restricted Stock Unit Awards under the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 23, 2012).

10.2.1		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 which amended Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on February 23, 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

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: May 3, 2012	By:	/s/ Steven A. Hartman
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer

Date: May 3, 2012	By:	/s/ Joan C. Sonnen
		Joan C. Sonnen
		Vice President and Controller