BAYTEX ENERGY USA, INC. - Quarter Report: 2011 June (Form 10-Q)

Unassociated Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

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

For the transition period from to

Commission File Number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

Virginia	23-1184320
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

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

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

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

Large accelerated filer	x	Accelerated filer	¨

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

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

As of July 29, 2011, 45,703,179 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2011

Table of Contents

Item		Page
	Part I - Financial Information

1.	Financial Statements	1
	Condensed Consolidated Statements of Income for the Three and Six Months Ended June 30, 2011 and 2010	1
	Condensed Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010	2
	Condensed Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010	3
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	4
	2. Basis of Presentation	4
	3. Acquisitions and Divestitures	4
	4. Accounts Receivable	5
	5. Derivative Instruments	5
	6. Property and Equipment	8
	7. Long-Term Debt	8
	8. Additional Balance Sheet Detail	11
	9. Fair Value Measurements	11
	10. Commitments and Contingencies	13
	11. Shareholders’ Equity and Comprehensive Income	14
	12. Share-Based Compensation	14
	13. Restructuring Activities	14
	14. Impairments	15
	15. Interest Expense	15
	16. Earnings per Share	16
	17. Discontinued Operations	16

Forward-Looking Statements		17

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	18
	Overview of Business	18
	Key Developments	19
	Results of Operations	21
	Liquidity and Capital Resources	33
	Environmental Matters	38
	Critical Accounting Estimates	38
	New Accounting Standards	38

3.	Quantitative and Qualitative Disclosures About Market Risk	39

4.	Controls and Procedures	40

	Part II - Other Information

6.	Exhibits	41

Signatures		42

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per share data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Revenues
Natural gas	$	38,300		$	38,819		$	79,489		$	86,807
Crude oil		21,548			10,875			38,131			24,721
Natural gas liquids (NGLs)		13,161			2,662			23,082			7,528
Gain (loss) on sale of property and equipment		(28	)		125			452			336
Other		637			807			1,047			1,774
Total revenues		73,618			53,288			142,201			121,166
Operating expenses
Lease operating		10,787			9,155			21,064			17,892
Gathering, processing and transportation		4,281			3,309			8,309			6,540
Production and ad valorem taxes		2,834			3,105			7,898			7,375
General and administrative		12,954			15,827			26,306			30,852
Exploration		19,368			9,541			48,916			15,570
Depreciation, depletion and amortization		33,036			32,105			67,879			62,134
Impairments		71,071			1,124			71,071			1,124
Other		-			-			-			465
Total operating expenses		154,331			74,166			251,443			141,952
Operating loss		(80,713	)		(20,878	)		(109,242	)		(20,786	)
Other income (expense)
Interest expense		(14,143	)		(13,321	)		(27,627	)		(26,992	)
Loss on extinguishment of debt		(24,238	)		-			(24,238	)		-
Derivatives		7,001			(580	)		8,329			29,297
Other		129			517			273			1,763
Loss from continuing operations before income taxes		(111,964	)		(34,262	)		(152,505	)		(16,718	)
Income tax benefit		40,046			13,165			54,247			6,387
Loss from continuing operations		(71,918	)		(21,097	)		(98,258	)		(10,331	)
Income from discontinued operations, net of tax		-			21,308			-			33,482
Gain on sale of discontinued operations, net of tax		-			49,612			-			49,612
Net income (loss)		(71,918	)		49,823			(98,258	)		72,763
Less net income attributable to noncontrolling interests in discontinued operations		-			(18,744	)		-			(28,090	)
Income (loss) attributable to Penn Virginia Corporation	$	(71,918	)	$	31,079		$	(98,258	)	$	44,673

Earnings (loss) per share attributable to Penn Virginia Corporation - Basic:
Continuing operations	$	(1.57	)	$	(0.46	)	$	(2.15	)	$	(0.23	)
Discontinued operations		-			0.06			-			0.12
Gain on sale of discontinued operations		-			1.08			-			1.09
Net income (loss)	$	(1.57	)	$	0.68		$	(2.15	)	$	0.98

Earnings (loss) per share attributable to Penn Virginia Corporation - Diluted:
Continuing operations	$	(1.57	)	$	(0.46	)	$	(2.15	)	$	(0.23	)
Discontinued operations		-			0.06			-			0.12
Gain on sale of discontinued operations		-			1.08			-			1.09
Net income (loss)	$	(1.57	)	$	0.68		$	(2.15	)	$	0.98

Weighted average shares outstanding, basic		45,768			45,539			45,724			45,508
Weighted average shares outstanding, diluted		45,768			45,790			45,724			45,767

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
	June 30,			December 31,
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	30,681		$	120,911
Accounts receivable, net of allowance for doubtful accounts		67,779			72,378
Derivative assets		14,440			16,818
Other current assets		3,904			4,233
Total current assets		116,804			214,340
Property and equipment, net (successful efforts method)		1,728,121			1,705,584
Derivative assets		2,547			3,889
Other assets		22,158			20,787
Total assets	$	1,869,630		$	1,944,600

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	89,324		$	99,661
Derivative liabilities		115			388
Deferred income taxes		3,113			4,318
Income taxes payable		2,820			2,627
Total current liabilities		95,372			106,994
Other liabilities		18,578			19,958
Deferred income taxes		276,405			330,836
Long-term debt		597,668			506,536

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 45,688,179 and 45,556,854 as of June 30, 2011 and December 31, 2010, respectively		269			267
Paid-in capital		685,559			680,981
Retained earnings		197,059			300,473
Deferred compensation obligation		3,235			2,743
Accumulated other comprehensive loss		(870	)		(938	)
Treasury stock – 162,209 and 125,357 shares of common stock, at cost, as of June 30, 2011 and December 31, 2010, respectively		(3,645	)		(3,250	)
Total shareholders’ equity		881,607			980,276
Total liabilities and shareholders’ equity	$	1,869,630		$	1,944,600

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)

	Six Months Ended June 30,
	2011			2010
Cash flows from operating activities
Net income (loss)	$	(98,258	)	$	72,763
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations:
Income from discontinued operations before income taxes		-			(36,832	)
Gain on sale of dicontinued operations before income taxes		-			(84,740	)
Non-cash portion of loss on extinguishment of debt		21,822			-
Depreciation, depletion and amortization		67,879			62,134
Impairments		71,071			1,124
Derivative contracts:
Net gains		(8,329	)		(29,297	)
Cash settlements		11,775			17,484
Deferred income tax benefit		(54,247	)		(7,733	)
Loss (gain) on the sale of property and equipment, net		(452	)		129
Dry hole and unproved leasehold expense		41,081			9,518
Non-cash interest expense		4,750			6,220
Share-based compensation		3,809			4,689
Other, net		265			(462	)
Changes in operating assets and liabilities, net		2,593			30,672
Net cash provided by operating activities from continuing operations		63,759			45,669

Cash flows from investing activities
Capital expenditures - property and equipment		(211,081	)		(168,081	)
Proceeds from the sale of PVG units, net		-			139,120
Proceeds from the sale of property and equipment, net		696			23,277
Other, net		100			1,192
Net cash used in investing activities for continuing operations		(210,285	)		(4,492	)

Cash flows from financing activities
Dividends paid		(5,156	)		(5,131	)
Proceeds from the issuance of Senior Notes due 2019		300,000			-
Repurchase of Convertible Notes		(232,963	)		-
Debt issuance costs paid		(6,559	)		-
Proceeds from the sale of PVG units, net		-			199,125
Distributions received from discontinued operations		-			11,218
Other, net		974			1,844
Net cash provided by financing activities from continuing operations		56,296			207,056

Cash flows from discontinued operations
Net cash provided by operating activities		-			77,759
Net cash used in investing activities		-			(18,112	)
Net cash used in financing activities		-			(59,647	)
Net cash provided by discontinued operations		-			-
Net increase (decrease) in cash and cash equivalents		(90,230	)		248,233
Cash and cash equivalents - beginning of period		120,911			79,017
Cash and cash equivalents - end of period	$	30,681		$	327,250

Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	19,705		$	20,975
Income taxes (net of refunds received)	$	(96	)	$	3,150

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 June 30, 2011

(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 primarily in the development, exploration and production of natural gas and oil 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 in consolidation. 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, 2010. Operating results for the six months ended June 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Certain amounts for the 2010 period have been reclassified to conform to the current year presentation.

There were neither any new accounting standards issued during the quarter ended June 30, 2011, nor any accounting standards pending adoption that would have a significant impact on our financial statements and notes to the financial statements.

Management has evaluated all activities of the Company through the date upon which the Condensed Consolidated Financial Statements were issued and concluded that, except for additional leasehold acquisitions in the Eagle Ford Shale (see Note 3), the execution of an agreement to sell substantially all of our assets in the Arkoma Basin (see Note 3) and the completion of a new credit agreement (“Revolver”)(see 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

During 2011, we acquired approximately 6,500 net Eagle Ford Shale acres in Gonzales County, Texas for approximately $24 million. The acreage acquired in these transactions is in close proximity to the Eagle Ford Shale acreage that we acquired during 2010. We are the operator of the acquired acreage with an average working interest of approximately 86%.

Divestitures

PVG Unit Offering

In March and April 2010, we sold 11.25 million common units of Penn Virginia GP Holdings, L.P. (“PVG”) for proceeds of $199.1 million, net of offering costs. At the time, the transaction reduced our limited partner interest in PVG to 22.6% and resulted in a $70.2 million increase to noncontrolling interests and a $82.1 million increase to additional paid-in capital, net of income tax effects. Because we maintained a controlling financial interest in PVG, the proceeds received from these transactions were reported as cash flows from financing activities on our Condensed Consolidated Statements of Cash Flows.

In June 2010, we completed the sale of our remaining PVG common units for $139.1 million, net of offering costs. Immediately prior to the closing of the June offering, we contributed 100% of the membership interests in PVG’s general partner to PVG, thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $49.6 million, net of income tax effects of $35.1 million, which is reported in the “Gain on sale of discontinued operations, net of tax” caption on our Condensed Consolidated Statements of Income. Because we no longer held any interests in PVG, the proceeds received from this transaction were reported as cash flows from investing activities on our Condensed Consolidated Statements of Cash Flows, and we deconsolidated PVG from our Consolidated Financial Statements. The results of operations and cash flows attributable to PVG for the 2010 period are presented in these Condensed Consolidated Financial Statements and Notes as discontinued operations.

Oil and Gas Properties

In July 2011, we executed an agreement to sell substantially all of our Arkoma Basin assets for approximately $30 million, excluding transaction costs and subject to customary purchase and sale adjustments. The transaction will be effective July 1, 2011 and we anticipate that it will close during the third quarter of 2011. The properties to be sold include approximately 73,000 net acres and proved reserves of approximately 42.5 billion cubic feet of natural gas equivalent. The carrying value of these properties as of June 30, 2011 was approximately $101 million. During the quarter ended June 30, 2011, we recognized an impairment of approximately $71 million with respect to these assets.

In January 2010, we completed the sale of all of our oil and gas properties in the Gulf Coast region (southern Texas and Louisiana) for cash proceeds of $23.2 million, net of transaction costs and certain purchase and sale adjustments, and the exchange of certain oil and gas properties located in the Gwinville field in northern Mississippi valued at $8.2 million.

4. Accounts Receivable

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

	June 30,			December 31,
	2011			2010
Revenue customers	$	51,050		$	44,783
Joint interest partners		16,707			23,526
Other		314			4,442
		68,071			72,751
Less: Allowance for doubtful accounts		(292	)		(373	)
	$	67,779		$	72,378

For the six months ended June 30, 2011 and 2010, four customers accounted for $84.0 million and $60.4 million, or approximately 60% and 51%, respectively, of our total consolidated product revenues. As of June 30, 2011 and December 31, 2010, $28.3 million and $31.1 million, or approximately 42% and 43%, respectively, 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 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 and swaps. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We determine the fair values of our oil and gas derivative instruments using third-party quoted forward prices for NYMEX Henry Hub natural gas and West Texas Intermediate crude oil as of the end of the reporting period and discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position.

The following table sets forth our commodity derivative positions as of June 30, 2011:

		Average
		Volume Per		Weighted Average Price				Fair Value
	Instrument	Day		Floor/Swap		Ceiling		Asset		Liability
		(in MMBtu)
Natural Gas:
Third quarter 2011	Costless collars		30,000	$	4.83	$	6.00	$	1,615	$	-
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50		2,703		-
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		2,349		-
Third quarter 2011	Swaps		40,000	$	5.06				2,532		-
Fourth quarter 2011	Swaps		10,000	$	5.01				399		-
First quarter 2012	Swaps		10,000	$	5.10				250		-
Second quarter 2012	Swaps		20,000	$	5.31				1,098		-
Third quarter 2012	Swaps		20,000	$	5.31				935		-
Fourth quarter 2012	Swaps		10,000	$	5.10				76		-

Crude Oil:		(barrels)
Third quarter 2011	Costless collars		360	$	80.00	$	103.30		-		24
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		-		91
First quarter 2012	Costless collars		500	$	100.00	$	120.00		317		-
Second quarter 2012	Costless collars		500	$	100.00	$	120.00		300		-
Third quarter 2012	Costless collars		500	$	100.00	$	120.00		292		-
Fourth quarter 2012	Costless collars		500	$	100.00	$	120.00		295		-
Third quarter 2011	Swaps		500	$	109.00				591		-
Fourth quarter 2011	Swaps		500	$	109.00				520		-
								$	14,272	$	115

Interest Rate Swaps

In December 2009, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the 10.375% Senior Notes due 2016 (“2016 Senior Notes”).

The following table sets forth the terms and positions of our interest rate swap assets as of the periods presented:

	Notional		Swap Interest Rates 1				June 30,		December 31,
Term	Amount		Pay	Receive			2011		2010
Through June 2013	$	100,000	LIBOR + 8.175%		10.375	%	$	2,715	$	2,590

1 References to LIBOR represent the 3-month rate.

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 Income. The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011			2010
Impact by contract type:
Commodity contracts	$	5,997	$	(2,860	)	$	7,305		$	25,352
Interest rate contracts		1,004		2,280			1,024			3,945
	$	7,001	$	(580	)	$	8,329		$	29,297
Realized and unrealized impact:
Cash received (paid) for:
Commodity contract settlements	$	4,133	$	8,789		$	10,877		$	17,824
Interest rate contract settlements		898		262			898			(340	)
		5,031		9,051			11,775			17,484
Unrealized gains (losses) attributable to:
Commodity contracts		1,864		(11,649	)		(3,572	)		7,528
Interest rate contracts		106		2,018			126			4,285
		1,970		(9,631	)		(3,446	)		11,813
	$	7,001	$	(580	)	$	8,329		$	29,297

The effects of derivative gains (losses) and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net income to net cash provided by operating activities from continuing operations. 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 periods presented:

		Fair Values as of
		June 30, 2011				December 31, 2010
Derivative		Derivative		Derivative		Derivative		Derivative
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

Interest rate contracts	Derivative assets/liabilities - current	$	1,765	$	-	$	1,743	$	-
Commodity contracts	Derivative assets/liabilities - current		12,675		115		15,075		388
			14,440		115		16,818		388

Interest rate contracts	Derivative assets/liabilities - noncurrent		950		-		847		-
Commodity contracts	Derivative assets/liabilities - noncurrent		1,597		-		3,042		-
			2,547		-		3,889		-
		$	16,987	$	115	$	20,707	$	388

As of June 30, 2011, we reported a commodity derivative asset of $14.3 million. The contracts associated with this position are with four counterparties, all of which are investment grade financial institutions, and are substantially concentrated with two 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 periods presented:

	June 30,			December 31,
	2011			2010
Oil and gas properties:
Proved	$	2,220,939		$	2,139,894
Unproved, net of amortization		170,721			171,303
Total oil and gas properties		2,391,660			2,311,197
Other property and equipment		16,217			15,589
Total property and equipment		2,407,877			2,326,786
Accumulated depreciation, depletion and amortization		(679,756	)		(621,202	)
	$	1,728,121		$	1,705,584

7. Long-Term Debt

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

	June 30,		December 31,
	2011		2010
Revolving credit facility	$	-	$	-
Senior notes due 2016, net of discount (principal amount of $300,000)		293,009		292,487
Senior notes due 2019		300,000		-
Convertible notes due 2012, net of discount (principal amount of $4,915 and $230,000)		4,659		214,049
	$	597,668	$	506,536

Revolving Credit Facility

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities (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%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees will be charged at 0.375% on the undrawn portion of the facility at current utilization levels and increasing to 0.500% based upon utilization levels in excess of 50% of the borrowing base.

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

We had no amounts outstanding under the previous revolving credit facility at any time during the six months ended June 30, 2011 other than letters of credit of $1.4 million which are still outstanding. As of June 30, 2011, our available borrowing capacity under the previous revolving credit facility, as reduced by such letters of credit and limited by our financial covenants, was approximately $160 million. Our initial available borrowing capacity under the Revolver, as reduced by our letters of credit and limited by the financial covenants described above, is approximately $264 million.

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 semi-annually in arrears 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 100.0% 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 7.25% Senior Notes due 2019 (“2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable semi-annually in arrears 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 100.0% 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% which is payable semi-annually in arrears 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%.

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, representing a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded from the net proceeds of the 2019 Senior Notes offering.

As a result of the tender offer, we recognized a pre-tax loss on extinguishment of debt of $25.9 million during the three months ended June 30, 2011, of which $24.2 million was charged to earnings and the remaining $1.7 million was charged directly to shareholders’ equity. The loss charged to earnings was determined as follows:

Cash paid to repurchase principal:
Allocated to liability component	$	231,331
Allocated to equity component		1,632
	$	232,963

Carrying value of liability component tendered:
Principal amount of Convertible Notes tendered	$	225,085
Pro rata share of original issue discount		(13,429	)
	$	211,656

Loss on extinguishment of debt:
Excess of liability component over carrying value	$	19,675
Write-off of pro rata share of debt issuance costs		2,147
Non-cash portion of loss on extinguishment		21,822
Transaction costs and fees paid		2,416
Pre-tax loss on extinguishment	$	24,238

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

	June 30,			December 31,
	2011			2010
Principal	$	4,915		$	230,000
Unamortized discount		(256	)		(15,951	)
Net carrying amount of liability component	$	4,659		$	214,049
Carrying amount of equity component	$	35,201		$	36,850

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Contractual interest expense	$	421	$	2,587	$	3,009	$	5,175
Accretion of original issue discount		318		1,817		2,265		3,609
Amortization of debt issuance costs		55		310		389		641
	$	794	$	4,714	$	5,663	$	9,425

In connection with the original sale of the Convertible Notes, we entered into convertible note hedge transactions (“Note Hedges”) with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes.

We also entered into separate warrant transactions (“Warrants”), whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share. Upon exercise of the Warrants, we will deliver shares of our common stock equal in value to the excess of the then market price over the strike price of the Warrants.

If the market value per share of our common stock at the time of conversion of the Convertible Notes exceeds the strike price of the Note Hedges, the Note Hedges entitle us to receive from the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount) based on the excess of the then current market price of our common stock over the strike price of the Note Hedges. Additionally, if the market price of our common stock at the time of exercise of the Warrants exceeds the strike price of the Warrants, we will owe the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount), not offset by the Note Hedges, in an amount based on the excess of the then current market price of our common stock over the strike price of the Warrants.

8. Additional Balance Sheet Detail

The following tables summarize components of selected balance sheet accounts as of the periods presented:

	June 30,		December 31,
	2011		2010
Other current assets:
Tubular inventory and well materials	$	2,256	$	3,600
Prepaid expenses		1,648		633
	$	3,904	$	4,233
Other assets:
Debt issuance costs	$	16,749	$	14,300
Long-term investments - SERP		5,363		6,440
Other		46		47
	$	22,158	$	20,787
Accounts payable and accrued liabilities:
Trade accounts payable	$	34,493	$	33,831
Drilling costs		24,052		31,770
Royalties		10,413		9,308
Production and franchise taxes		4,593		6,012
Compensation		5,100		9,631
Interest		6,241		2,977
Other		4,432		6,132
	$	89,324	$	99,661
Other liabilities:
Asset retirement obligation	$	7,312	$	7,364
Pension		1,700		1,766
Postretirement health care		2,978		2,976
Deferred compensation		5,688		6,952
Other		900		900
	$	18,578	$	19,958

9. Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive to sell an asset or 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, 2010.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of June 30, 2011, 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 tables summarize the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for the same or similar issues as of the periods presented:

	June 30, 2011				December 31, 2010
	Fair		Carrying		Fair		Carrying
	Value		Value		Value		Value
10.375% Senior Notes due 2016	$	330,000	$	293,009	$	335,712	$	292,487
7.25% Senior Notes due 2019		289,500		300,000		-		-
4.50% Convertible Notes due 2012		5,047		4,659		225,975		214,049
	$	624,547	$	597,668	$	561,687	$	506,536

Recurring Fair Value Measurements

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

	June 30, 2011
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Publicly traded equity securities	$	5,363		$	5,363		$	-		$	-
Interest rate swap assets - current		1,765			-			1,765			-
Interest rate swap assets - noncurrent		950			-			950			-
Commodity derivative assets - current		12,675			-			12,675			-
Commodity derivative assets - noncurrent		1,597			-			1,597			-

Liabilities:
Deferred compensation - noncurrent liability		(5,685	)		(5,685	)		-			-
Commodity derivative liabilities - current		(115	)		-			(115	)		-
Totals	$	16,550		$	(322	)	$	16,872		$	-

	December 31, 2010
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Publicly traded equity securities	$	6,440		$	6,440		$	-		$	-
Interest rate swap assets - current		1,743			-			1,743			-
Interest rate swap assets - noncurrent		847			-			847			-
Commodity derivative assets - current		15,075			-			15,075			-
Commodity derivative assets - noncurrent		3,042			-			3,042			-

Liabilities:
Deferred compensation - noncurrent liability		(6,948	)		(6,948	)		-			-
Commodity derivative liabilities - current		(388	)		-			(388	)		-
Totals	$	19,811		$	(508	)	$	20,319		$	-

We used the following methods and assumptions to estimate fair values:

•

Publicly traded equity securities: We hold various publicly traded equity securities as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.

•

Commodity derivatives: We determine the fair values of our oil and gas derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub natural 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.

•

Deferred compensation: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain publicly traded equity securities. The fair values of these obligations 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 and 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.

In addition to these non-recurring fair value measurements, we utilized fair value measurements in the determination of the loss on the extinguishment of approximately 98% our Convertible Notes. In connection with that determination, we were required to allocate the cash paid to repurchase the Convertible Notes to its liability and equity components. Furthermore, the allocation to the liability component was based on the fair value of a comparable debt instrument that has no conversion feature. The residual amount of cash paid to repurchase the Convertible Notes was allocated to the equity component.

10. Commitments and Contingencies

Commitments

Our most significant commitments consist of operating lease rentals for equipment and office space, the purchase of oil and gas well drilling services and capacity utilization under firm transportation service agreements, as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 or results of operations. During 2010, we established a $0.9 million reserve for a litigation matter and a $0.5 million reserve for a sales and use tax audit contingency. In addition, as of June 30, 2011, we have recorded AROs of $7.3 million attributable to the plugging of abandoned wells.

11. Shareholders’ Equity and Comprehensive Income

The following table is a reconciliation of the carrying amounts of total shareholders’ equity attributable to Penn Virginia and shareholders’ equity attributable to the noncontrolling interests in PVG for the periods presented:

	Penn Virginia			Noncontrolling
	Corporation			Interests in			Total
	Shareholders'			Discontinued			Shareholders'			Comprehensive
	Equity			Operations			Equity			Income (Loss)
Balance as of December 31, 2010	$	980,276		$	-		$	980,276
Dividends paid ($0.1125 per share)		(5,156	)		-			(5,156	)
Other changes to shareholders' equity		4,677			-			4,677
Comprehensive income:
Net loss		(98,258	)		-			(98,258	)	$	(98,258	)
Other, net of tax		68			-			68			68
Balance as of June 30, 2011	$	881,607		$	-		$	881,607		$	(98,190	)

Balance as of December 31, 2009	$	908,088		$	329,911		$	1,237,999
Dividends paid ($0.1125 per share)		(5,131	)		-			(5,131	)
Distributions to noncontrolling interest holders		-			(49,566	)		(49,566	)
Sale of PVG units, net of tax		82,102			70,188			152,290
Deconsolidation of PVG		-			(382,324	)		(382,324	)
Other changes to shareholders' equity		5,286			3,119			8,405
Comprehensive income:
Net income		44,673			28,090			72,763		$	72,763
Hedging reclassification adjustment		-			582			582			582
Other, net of tax		(204	)		-			(204	)		(204	)
Balance as of June 30, 2010	$	1,034,814		$	-		$	1,034,814		$	73,141

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 are vested 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, 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 Income. The following table summarizes the share-based compensation expense for the periods presented:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Stock option plans	$	1,379	$	1,276	$	2,787	$	3,385
Common, deferred and restricted stock and restricted stock unit plans		634		392		1,022		1,304
	$	2,013	$	1,668	$	3,809	$	4,689

13. Restructuring Activities

During 2009 and 2010, we implemented an organization restructuring in connection with our transformation to a pure play development, exploration and production company. The restructuring resulted in the termination of approximately 30 employees and the transfer of certain corporate and division operations functions from our former Kingsport, Tennessee location to our Houston, Texas and Pittsburgh and Radnor, Pennsylvania locations. We incurred special termination benefit costs, relocation costs and other incremental costs associated with staffing and expanding our office locations.

These restructuring charges are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Income and are comprised of the following for the periods presented:

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Termination benefits	$	-	$	5	$	-	$	867
Employee and office relocation costs		52		515		70		675
Other incremental costs		-		150		-		605
Lease assignment charge		-		3,500		-		3,500
	$	52	$	4,170	$	70	$	5,647

The following table summarizes the termination benefit obligations as of and for the six months ended June 30,:

	2011			2010
Balance at beginning of period	$	64		$	529
Termination benefits accrued		-			867
Cash payments		(64	)		(1,396	)
Balance at end of period	$	-		$	-

14. Impairments

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2011		2010		2011		2010
Oil and gas properties	$	71,071	$	-	$	71,071	$	-
Other		-		1,124		-		1,124
	$	71,071	$	1,124	$	71,071	$	1,124

During the three months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011. As disclosed in Note 3, we executed an agreement to sell these properties in July 2011.

15. Interest Expense

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Interest on borrowings and related fees	$	13,120		$	10,709		$	23,867		$	21,487
Accretion on original issue discount		583			2,001			2,788			4,111
Amortization of debt issuance costs		895			964			1,962			2,109
Capitalized interest		(455	)		(355	)		(990	)		(717	)
Other, net		-			2			-			2
	$	14,143		$	13,321		$	27,627		$	26,992

16. Earnings per Share

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Loss from continuing operations	$	(71,918	)	$	(21,097	)	$	(98,258	)	$	(10,331	)
Income from discontinued operations, net of tax 1		-			21,308			-			33,482
Gain on sale of dicontinued operations		-			49,612			-			49,612
Less: Net income attributable to noncontrolling interests		-			(18,744	)		-			(28,090	)
Net income (loss) attributable to common shareholders	$	(71,918	)	$	31,079		$	(98,258	)	$	44,673
Less: Portion of subsidiary net income allocated to undistributed share-basd compensation awards, net of tax		-			-			-			(28	)
	$	(71,918	)	$	31,079		$	(98,258	)	$	44,645

Weighted-average shares, basic		45,768			45,539			45,724			45,508
Effect of dilutive securities 2		-			251			-			259
Weighted-average shares, diluted		45,768			45,790			45,724			45,767

1	For purposes of determining earnings per share, net income attributable to noncontrolling interests, which is fully attributable to PVG's operations, is applied against income from discontinued operations.

For both the three and six months ended June 30, 2011, approximately 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.

17. Discontinued Operations

Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001. Our ownership interests in PVR were held principally through our general and limited partner interests in PVG. During June 2010, we disposed of our remaining ownership interests in PVG and, indirectly, our interests in PVR.

Income from discontinued operations represents the results of operations of PVG, which include the results of operations of PVR. Previously, the results of operations of PVG and PVR were presented as our coal and natural resource management and natural gas midstream segments. The table below reflects the results of operations of PVG for the periods presented.

	Three Months Ended June 30,					Six Months Ended June 30,
	2011		2010			2011		2010
Revenues	$	-	$	115,573		$	-	$	303,206

Income from discontinued operations before taxes	$	-	$	22,877		$	-	$	36,832
Income tax expense 1		-		(1,569	)		-		(3,350	)
Income from discontinued operations, net of taxes	$	-	$	21,308		$	-	$	33,482

1 Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to PVG's operations.

PVR continues to provide marketing and gas gathering and processing services to the Company under a number of existing agreements with various remaining terms. We continue to sell gas to PVR for resale at PVR’s Crossroads plant in east Texas.

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;

•

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;

•

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 costs 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;

•

uncertainties related to expected benefits from acquisitions of oil and natural gas properties;

•

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, 2010.

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 primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions. We have a geographically diverse asset base with core areas of operations in Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of December 31, 2010, we had proved natural gas and oil reserves of approximately 942 Bcfe. Our operations include the drilling of both unconventional and development opportunities, as well as exploratory prospects.

The primary development play types that we are currently focused on include: (i) the Eagle Ford Shale play in South Texas and (ii) the horizontal Granite Wash play in the Mid-Continent. We are also drilling exploratory wells in the Marcellus Shale play in Appalachia to determine whether our leasehold acreage position there will support a development program.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2011			2010			2011			2010
Total production (MMcfe)		11,699			10,475			23,870			20,813
Daily production (MMcfe per day)		128.6			115.1			131.9			115.0

Realized prices per Mcfe, as reported	$	6.24		$	5.00		$	5.89		$	5.72
Realized prices per Mcfe, adjusted for derivatives	$	6.59		$	5.84		$	6.35		$	6.58

Product revenues, as reported	$	73,009		$	52,356		$	140,702		$	119,056
Product revenues, as adjusted for derivatives	$	77,142		$	61,145		$	151,579		$	136,881

Operating loss	$	(80,713	)	$	(20,878	)	$	(109,242	)	$	(20,786	)
Interest expense	$	14,143		$	13,321		$	27,627		$	26,992

Cash provided by operating activities	$	34,323		$	14,924		$	63,759		$	45,669
Cash paid for capital expenditures	$	110,352		$	103,589		$	211,081		$	168,081

Cash and cash equivalents at end of period							$	30,681		$	327,250
Debt outstanding, net of discounts, at end of period							$	597,668		$	500,537
Credit available under revolving credit facility at end of period 1							$	160,730		$	299,268
Net development wells drilled		12.0			13.1			14.4			20.8
Net exploratory wells drilled		1.1			-			6.4			1.0

1 As limited by our financial covenants.

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, Marcellus Shale and Granite Wash plays, (ii) entrance into a new credit facility, (iii) execution of an agreement to sell Arkoma Basin assets, (iv) the offering and sale of $300 million of our 7.25% Senior Notes due 2019, or 2019 Senior Notes, and the tender offer to repurchase our 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes, and (v) acquiring properties in the Eagle Ford Shale play. A discussion of these key developments follows:

Drilling Results and Future Development

During the six months ended June 30, 2011, we drilled a total of 20.8 net wells, including 9.2 net wells in the Eagle Ford Shale, 4.3 net wells in the Marcellus Shale and 7.3 net wells in the Mid-Continent region, primarily in the Granite Wash.

Six of the Eagle Ford Shale wells, in which we have an approximate 83% working interest, have been completed and in June were producing an aggregate of 1,740 barrels of oil per day, or BOPD, and 0.33 million cubic feet of natural gas, or MMcf, per day on a net basis. As of July 29, 2011 we have completed 12 Eagle Ford Shale wells and our production is estimated at 5,000 barrels of oil equivalent per day on a net basis. Our natural gas midstream service provider recently connected our Eagle Ford Shale wells to its pipeline and processing facilities resulting in the recognition of sales revenue associated with natural gas liquids, or NGLs, and residue gas production. The natural gas associated with these wells is expected to yield approximately 150 barrels of NGLs per MMcf. We expect to continue drilling in this region for the remainder of 2011 and beyond. We recently extended our agreement with a hydraulic fracturing services contractor to provide these services in the Eagle Ford Shale, as well as other plays in East Texas and Oklahoma through July 2012. During the second half of 2011, we have allocated approximately $142 million for development drilling capital expenditures primarily in the Eagle Ford Shale.

We completed three horizontal test wells in the Marcellus Shale located in the central portion of our approximately 35,000 net acreage position in Potter and Tioga counties, Pennsylvania. These wells resulted in an average rate that ranged from 1.7 to 2.7 MMcf per day over a 72-hour test period. We expect that the wells will be connected to a pipeline in September 2011. We will monitor long-term production to determine if the reserves can support a development program in this immediate area. We are also evaluating alternative engineering techniques with respect to drilling and completion activities in this relatively undeveloped geological area. During the second half of 2011, we plan to begin testing the eastern portion of our acreage, which is comprised of approximately 20,000 net acres.

In the Mid-Continent region, we successfully completed 4.6 net development wells in the Granite Wash. However, our exploratory program resulted in 3 dry holes (2.6 net) at an aggregate cost of $18.5 million. We do not plan any further exploratory activities in the Mid-Continent region during 2011. We plan to continue with our Granite Wash development program in this region, primarily operated by our partners.

Completion of a New Credit Facility

In August 2011, we entered into a new revolving credit agreement, or Revolver. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The initial borrowing base is set at $400 million and will be redetermined semi-annually, the next being scheduled in October 2011. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon additional commitments from one or more lenders. The financial covenant that determines the permitted leverage ratio (net debt divided by Adjusted EBITDAX, as defined in the Revolver) increased to 4.5 through June 30, 2013, after which it will be 4.0.

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. The Revolver will mature in August 2016.

Disposition of Arkoma Basin Properties

In July 2011, we executed an agreement for the sale of substantially all of our Arkoma Basin assets for approximately $30 million excluding transaction costs and subject to customary purchase and sale adjustments. The transaction will be effective July 1, 2011 and we anticipate that it will close during the third quarter of 2011. During the quarter ended June 30, 2011, we recognized an impairment of approximately $71 million with respect to these assets. Upon the closing of the transaction, the borrowing base under the Revolver will decrease by $20 million to $380 million.

Senior Note Offering and Tender Offer to Repurchase Convertible Notes

In April 2011, we completed the offering of our 2019 Senior Notes. Total proceeds received from the offering were $293.5 million, net of underwriting and debt issuance costs. We used $237.1 million of the proceeds to repurchase approximately 98% of our Convertible Notes plus accrued interest, and we have a total of $4.9 million (principal amount) of Convertible Notes currently outstanding. We used the remainder of the proceeds to provide working capital for general corporate purposes, including capital expenditures.

Property Acquisitions

During 2011, we acquired approximately 6,500 net Eagle Ford Shale acres in Gonzales County, Texas for approximately $24 million. This acreage is in close proximity to the Eagle Ford Shale acreage that we acquired during 2010. We are the operator of the acquired acreage with an average working interest of approximately 86%.

Results of Operations

Three Months Ended June 30, 2011 Compared With Three Months Ended June 30, 2010

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

	Three Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		8,869			9,132			(264	)		(3	)%
Crude oil (MBbl)		219			148			71			48	%
NGL (MBbl)		253			76			177			232	%
Total production (MMcfe)		11,699			10,475			1,224			12	%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.32		$	4.25		$	0.07			2	%
Crude oil ($/Bbl)		98.45			73.64			24.81			34	%
NGL ($/Bbl)		52.04			34.97			17.08			49	%
Total ($/Mcfe)	$	6.24		$	5.00		$	1.24			25	%

Revenues
Natural gas	$	38,300		$	38,819		$	(519	)		(1	)%
Crude oil		21,548			10,875			10,673			98	%
NGL		13,161			2,662			10,499			394	%
Total product revenues		73,009			52,356			20,653			39	%
Gain (loss) on sale of property and equipment		(28	)		125			(153	)		(122	)%
Other income		637			807			(170	)		(21	)%
Total revenues		73,618			53,288			20,330			38	%

Operating Expenses
Lease operating		10,787			9,155			(1,632	)		(18	)%
Gathering, processing and transportation		4,281			3,309			(972	)		(29	)%
Production and ad valorem taxes		2,834			3,105			271			9	%
General and administrative		12,954			15,827			2,873			18	%
Exploration		19,368			9,541			(9,827	)		(103	)%
Depreciation, depletion and amortization		33,036			32,105			(931	)		(3	)%
Impairments		71,071			1,124			(69,947	)	NM
Total operating expenses		154,331			74,166			(80,165	)		(108	)%

Operating loss		(80,713	)		(20,878	)		(59,835	)		(287	)%
Other income (expense)
Interest expense		(14,143	)		(13,321	)		(822	)		(6	)%
Loss on extinguishment of debt		(24,238	)		-			(24,238	)	NM
Derivatives		7,001			(580	)		7,581		NM
Other		129			517			(388	)		(75	)%
Loss from continuing operations before income taxes		(111,964	)		(34,262	)		(77,702	)		(227	)%
Income tax benefit		40,046			13,165			26,881			204	%
Loss from continuing operations		(71,918	)		(21,097	)		(50,821	)		(241	)%
Income from discontinued operations, net of tax		-			21,308			(21,308	)	NM
Gain on sale of discontinued operations		-			49,612			(49,612	)	NM
Net income (loss)		(71,918	)		49,823			(121,741	)		(244	)%
Less net income attributable to noncontrolling interests		-			(18,744	)		18,744		NM
Income (loss) attributable to Penn Virginia Corporation	$	(71,918	)	$	31,079		$	(102,997	)		(331	)%

NM - Not meaningful.

Production

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

	Three Months Ended June 30,				Favorable			Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
Texas		4,224		2,618		1,606			46.4		28.8		17.7			61	%
Appalachia		2,251		2,591		(340	)		24.7		28.5		(3.7	)		(13	)%
Mid-Continent		3,527		3,502		25			38.8		38.5		0.3			1	%
Mississippi		1,697		1,764		(67	)		18.6		19.4		(0.7	)		(4	)%
Total production		11,699		10,475		1,224			128.6		115.1		13.5			12	%

Approximately 24% of production on an equivalent basis in the three months ended June 30, 2011 was attributable to oil and NGLs, an 85% increase compared to the corresponding period in 2010. The shift in production mix reflects our focus on emerging oil and liquids-rich plays in Eagle Ford Shale in Texas and the Mid-Continent region. Our Eagle Ford Shale production came on line during the first quarter of 2011 and significantly ramped up during the latter portion of the second quarter. During the quarter ended June 30, 2011, our Eagle Ford Shale production represented approximately 16% of our total production in Texas and 6% of our total production. Our natural gas midstream service provider connected our Eagle Ford Shale wells to its pipeline and processing facilities in June 2011 resulting in the recognition of sales revenue associated with NGL and residue gas production.

Product Revenues and Prices

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

	Three Months Ended June 30,				Favorable			Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)
								($ per Mcfe)
Texas	$	30,860	$	12,390	$	18,470		$	7.31	$	4.73	$	2.57
Appalachia		9,769		10,583		(814	)		4.34		4.08		0.25
Mid-Continent		24,292		21,763		2,529			6.89		6.21		0.67
Mississippi		8,088		7,620		468			4.77		4.32		0.45
Total revenues	$	73,009	$	52,356	$	20,653		$	6.24	$	5.00	$	1.24

As illustrated below, higher oil and NGL production volume coupled with improved oil and NGL pricing were the significant factors for increasing revenues. In addition, the current period results include revenue of $4.3 million received upon settlement of a revenue audit claim relating to a prior period. The following table provides an analysis of the change in our revenues for the three months ended June 30, 2011 as compared to the three months ended June 30, 2010:

	Revenue Variance Due to
	Volume			Price		Total
Natural gas	$	(1,120	)	$	601	$	(519	)
Crude oil		5,243			5,430		10,673
NGL		6,181			4,318		10,499
	$	10,304		$	10,350	$	20,653

Effects of Derivatives

As part of our risk management strategy, we use derivative instruments to hedge against fluctuations in natural gas and oil prices. We received $4.1 million and $8.8 million in net cash settlements from commodity derivatives in the three months ended June 30, 2011 and 2010.

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

	Three Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Natural gas revenues as reported	$	38,300		$	38,819		$	(519	)		(1	)%
Cash settlements on natural gas derivatives, net		4,261			9,038			(4,777	)		(53	)%
Natural gas revenues adjusted for derivatives	$	42,561		$	47,857		$	(5,296	)		(11	)%

Natural gas prices per Mcf, as reported	$	4.32		$	4.25		$	0.07			2	%
Cash settlements on natural gas derivatives per Mcf		0.48			0.99			(0.51	)		(51	)%
Natural gas prices per Mcf adjusted for derivatives	$	4.80		$	5.24		$	(0.44	)		(8	)%

Crude oil revenues as reported	$	21,548		$	10,875		$	10,673			98	%
Cash settlements on crude oil derivatives, net		(128	)		(249	)		121			49	%
Crude oil revenues adjusted for derivatives	$	21,420		$	10,626		$	10,794			102	%

Crude oil prices per Bbl, as reported	$	98.45		$	73.64		$	24.81			34	%
Cash settlements on crude oil derivatives per Bbl		(0.58	)		(1.68	)		1.10			65	%
Crude oil prices per Bbl adjusted for derivatives	$	97.87		$	71.96		$	25.91			36	%

Gain (Loss) on Sale of Property and Equipment

During both the 2011 and 2010 periods, we recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well materials.

Other Income

Other income decreased primarily as a result of lower gathering revenues during the 2011 period.

Operating Expenses

The following table summarizes certain of our operating expenses per Mcfe for the periods presented:

	Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Lease operating	$	0.92	$	0.87	$	(0.05	)		(5	)%
Gathering, processing and transportation		0.37		0.32		(0.05	)		(16	)%
Production and ad valorem taxes		0.24		0.30		0.06			19	%
General and administrative		1.11		1.51		0.40			27	%
General and administrative excluding share-based
compensation and restructuring charges		0.93		0.95		0.02			2	%
Depreciation, depletion and amortization		2.82		3.06		0.24			8	%

Lease Operating

Lease operating expense increased on an absolute basis and a per-unit basis in the 2011 period due to higher maintenance and compression costs as well as higher workover costs incurred across the Company. In addition, certain other costs, including water disposal, were generally higher commensurate with higher production volumes during the 2011 period.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during the 2011 period due to overall higher production volumes as well as higher processing costs associated with NGLs. The production of NGLs during the 2011 period represents a significantly larger proportion of the total production volume compared to the 2010 period.

Production and Ad Valorem Taxes

On an absolute basis, production and ad valorem taxes decreased during the 2011 period due primarily to a production tax settlement with the State of Oklahoma offset partially by the effects of higher production volumes. As a percentage of product revenue, production and ad valorem taxes decreased to 3.9% during the 2011 period from 5.9% during the 2010 period.

General and Administrative

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

	Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Recurring general and administrative expenses	$	10,889	$	9,989	$	(900	)		(9	)%
Share-based compensation		2,013		1,668		(345	)		(21	)%
Restructuring expenses		52		4,170		4,118			99	%
	$	12,954	$	15,827	$	2,873			18	%

Recurring general and administrative expenses increased primarily due to higher compensation and employee benefits charges offset partially by lower insurance costs. Share-based compensation charges increased during the 2011 period due primarily to a change in the timing of the grant of certain awards such that the second quarter of 2011 reflects two grants while the 2010 period includes only one. Organization restructuring expenses during the 2010 period include termination benefits and office and employee relocation costs as well as a $3.5 million charge related to the assignment of the lease of our former Kingsport, Tennessee office facility. Certain costs, primarily employee relocation expenses, continue to be incurred during 2011.

Exploration

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

	Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Dry hole costs	$	2,116	$	-	$	(2,116	)	NM
Geological and geophysical		4,302		4,065		(237	)		(6	)%
Unproved leasehold		11,966		4,435		(7,531	)		(170	)%
Other, primarily delay rentals		984		1,041		57			5	%
	$	19,368	$	9,541	$	(9,827	)		(103	)%

The increase includes higher amortization of unproved leaseholds due primarily to the effect of significant acquisitions during 2010. Dry hole costs incurred during the 2011 period are due primarily to a well in the Mid-Continent region.

Depreciation, Depletion and Amortization (DD&A)

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

	Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Depletion	$	31,606	$	30,279	$	(1,327	)		(4	)%
Depreciation - Oil and gas operations		619		645		26			4	%
Depreciation - Corporate		679		1,070		391			37	%
Amortization		132		111		(21	)		(19	)%
	$	33,036	$	32,105	$	(931	)		(3	)%

	DD&A Variance Due to
	Production			Rates		Total
Three months ended June 30, 2011 compared to 2010	$	(3,752	)	$	2,821	$	(931	)

Higher depletion during the 2011 period is commensurate with higher production volumes while the decrease in depreciation is primarily the result of the disposition of certain corporate assets during the prior year in connection with the 2010 organization restructuring. Our average depletion rate decreased to $2.70 per Mcfe for the 2011 period from $2.89 per Mcfe for the 2010 period.

Impairments

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

	Three Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Oil and gas properties	$	71,071	$	-	$	(71,071	)		NM
Other		-		1,124		1,124			NM
	$	71,071	$	1,124	$	(69,947	)		NM

During the three months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011. In July 2011, we executed an agreement to sell these properties.

Interest Expense

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

	Three Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Interest on borrowings and related fees	$	13,120		$	10,709		$	(2,411	)		(23	)%
Accretion of original issue discount		583			2,001			1,506			75	%
Amortization of debt issuance costs		895			964			(19	)		(2	)%
Capitalized interest		(455	)		(355	)		100			28	%
Other, net		-			2			2		NM
	$	14,143		$	13,321		$	(822	)		(6	)%

The issuance of the 2019 Senior Notes at 7.25%, offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate at 8.5%, added over $88 million net principal amount of debt outstanding. Accordingly, interest expense increased moderately due to higher average amounts of debt outstanding partially offset by lower effective interest rates. Capitalized interest was higher during the 2011 period due to higher carrying values on eligible capital projects.

Loss on Extinguishment of Debt

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

Derivatives

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

	Three Months Ended June 30,					Favorable
	2011		2010			(Unfavorable)			% Change
Oil and gas derivative unrealized derivative gain (loss)	$	1,864	$	(11,649	)	$	13,513			116	%
Oil and gas derivative realized gain		4,133		8,789			(4,656	)		(53	)%
Interest rate swap unrealized gain		106		2,018			(1,912	)		(95	)%
Interest rate swap realized gain		898		262			636			243	%
	$	7,001	$	(580	)	$	7,581		(1307		)%

Cash received for settlements during the three months ended June 30, 2011 was $5.0 million compared to $9.1 million during the second quarter of 2010.

Other

Other income decreased during the 2011 period because the higher interest income earned on higher average cash balances was more than offset by gains on the sale of non-operating investments recognized during the 2010 period.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2011 was 35.8% compared to 38.4% for the 2010 period. Due to operating losses incurred during the second quarter of 2011, we recognized an income tax benefit. In addition, the effective tax rate for the 2011 period includes a deferred tax asset valuation allowance due primarily to the inability to recognize a tax benefit for certain state net operating losses.

Discontinued Operations

The following table presents a summary of results of operations from discontinued operations for the periods presented:

	Three Months Ended June 30,
	2011		2010
Revenues	$	-	$	115,573

Income from discontinued operations before taxes	$	-	$	22,877
Income tax expense 1		-		(1,569	)
	$	-	$	21,308

1	Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to PVG's operations.

Gain on Sale of Discontinued Operations

In June 2010, we completed the sale of all of our remaining interest in Penn Virginia GP Holdings, L.P., or PVG, for $139.1 million net of offering costs and contributed 100% of the membership interests in PVG’s general partner to PVG, thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $49.6 million, net of income tax effects of $35.1 million. Final sale adjustments were recorded during the fourth quarter of 2010.

Six Months Ended June 30, 2011 Compared With Six Months Ended June 30, 2010

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

	Six Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		18,594			17,700			894			5	%
Crude oil (MBbl)		407			334			73			22	%
NGL (MBbl)		473			185			288			155	%
Total production (MMcfe)		23,870			20,813			3,058			15	%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.27		$	4.90		$	(0.63	)		(13	)%
Crude oil ($/Bbl)		93.80			74.09			19.71			27	%
NGL ($/Bbl)		48.82			40.66			8.16			20	%
Total ($/Mcfe)	$	5.89		$	5.72		$	0.17			3	%

Revenues
Natural gas	$	79,489		$	86,807		$	(7,318	)		(8	)%
Crude oil		38,131			24,721			13,410			54	%
NGL		23,082			7,528			15,554			207	%
Total product revenues		140,702			119,056			21,646			18	%
Gain on sale of property and equipment		452			336			116			35	%
Other income		1,047			1,774			(727	)		(41	)%
Total revenues		142,201			121,166			21,035			17	%

Operating Expenses
Lease operating		21,064			17,892			(3,172	)		(18	)%
Gathering, processing and transportation		8,309			6,540			(1,769	)		(27	)%
Production and ad valorem taxes		7,898			7,375			(523	)		(7	)%
General and administrative		26,306			30,852			4,546			15	%
Exploration		48,916			15,570			(33,346	)		(214	)%
Depreciation, depletion and amortization		67,879			62,134			(5,745	)		(9	)%
Impairments		71,071			1,124			(69,947	)	NM
Other		-			465			465			100	%
Total operating expenses		251,443			141,952			(109,491	)		(77	)%

Operating loss		(109,242	)		(20,786	)		(88,456	)		(426	)%
Other income (expense)
Interest expense		(27,627	)		(26,992	)		(635	)		(2	)%
Loss on extinguishment of debt		(24,238	)		-			(24,238	)	NM
Derivatives		8,329			29,297			(20,968	)		(72	)%
Other		273			1,763			(1,490	)		(85	)%
Loss from continuing operations before income taxes		(152,505	)		(16,718	)		(135,787	)		(812	)%
Income tax benefit		54,247			6,387			47,860			749	%
Loss from continuing operations		(98,258	)		(10,331	)		(87,927	)		(851	)%
Income from discontinued operations, net of tax		-			33,482			(33,482	)	NM
Gain on sale of discontinued operations		-			49,612			(49,612	)	NM
Net income (loss)		(98,258	)		72,763			(171,021	)		(235	)%
Less net income attributable to noncontrolling interests		-			(28,090	)		28,090		NM
Income (loss) attributable to Penn Virginia Corporation	$	(98,258	)	$	44,673		$	(142,931	)		(320	)%

NM - Not meaningful.

Production

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

	Six Months Ended June 30,				Favorable			Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
Texas		8,050		5,201		2,849			44.5		28.7		15.7			55	%
Appalachia		4,615		5,187		(572	)		25.5		28.7		(3.2	)		(11	)%
Mid-Continent		7,648		6,714		934			42.3		37.1		5.2			14	%
Mississippi		3,557		3,416		141			19.7		18.9		0.8			4	%
Gulf Coast (Divested)		-		295		(295	)		-		1.6		(1.6	)		(100	)%
Total production		23,870		20,813		3,057			131.9		115.0		16.9			15	%

Approximately 22% of total production on an equivalent basis in the six months ended June 30, 2011 was attributable to oil and NGLs, a 47% increase compared to the corresponding period in 2010. 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. Oil and NGL production comprised over 31% and 36% of our total production in Texas and the Mid-Continent region through the first half of 2011. Our Eagle Ford Shale production came on line during the first quarter of 2011 and significantly ramped up during the latter portion of the second quarter. We anticipate that this shift in production mix will continue as an increasing proportion of our development plans is focused on liquids plays.

Product Revenues and Prices

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

	Six Months Ended June 30,				Favorable			Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)
								($ per Mcfe)
Texas	$	51,926	$	28,407	$	23,519		$	6.45	$	5.46	$	0.99
Appalachia		19,589		24,608		(5,019	)		4.24		4.74		(0.50	)
Mid-Continent		52,899		47,082		5,817			6.92		7.01		(0.09	)
Mississippi		16,288		16,783		(495	)		4.58		4.91		(0.33	)
Gulf Coast (Divested)		-		2,176		(2,176	)		-		7.38		(7.38	)
Total revenues	$	140,702	$	119,056	$	21,646		$	5.89	$	5.72	$	0.17

As illustrated below, higher production volumes coupled with improved oil and NGL pricing were the significant factors for increasing revenues. However, the overall increase was substantially offset by lower natural gas prices. The following table provides an analysis of the change in our revenues for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010:

	Revenue Variance Due to
	Volume		Price			Total
Natural gas	$	4,386	$	(11,704	)	$	(7,318	)
Crude oil		5,397		8,013			13,410
NGL		11,698		3,856			15,554
	$	21,481	$	165		$	21,646

Effects of Derivatives

As part of our risk management strategy, we use derivative instruments to hedge against fluctuations in natural gas and oil prices. We received $10.9 million and $17.8 million in cash settlements from commodity derivatives in the six months ended June 30, 2011 and 2010.

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

	Six Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Natural gas revenues as reported	$	79,489		$	86,807		$	(7,318	)		(8	)%
Cash settlements on natural gas derivatives, net		11,230			17,927			(6,697	)		(37	)%
Natural gas revenues adjusted for derivatives	$	90,719		$	104,734		$	(14,015	)		(13	)%

Natural gas prices per Mcf, as reported	$	4.27		$	4.90		$	(0.63	)		(13	)%
Cash settlements on natural gas derivatives per Mcf		0.61			1.02			(0.41	)		(40	)%
Natural gas prices per Mcf adjusted for derivatives	$	4.88		$	5.92		$	(1.04	)		(18	)%

Crude oil revenues as reported	$	38,131		$	24,721		$	13,410			54	%
Cash settlements on crude oil derivatives, net		(353	)		(102	)		(251	)		(246	)%
Crude oil revenues adjusted for derivatives	$	37,778		$	24,619		$	13,159			53	%

Crude oil prices per Bbl, as reported	$	93.80		$	74.09		$	19.71			27	%
Cash settlements on crude oil derivatives per Bbl		(0.87	)		(0.31	)		(0.56	)		(184	)%
Crude oil prices per Bbl adjusted for derivatives	$	92.93		$	73.78		$	19.15			26	%

Gain on Sale of Property and Equipment

During both the 2011 and 2010 periods, we recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materials.

Other Income

Other income decreased primarily as a result of lower gathering revenues during the 2011 period and the effect of a compression service settlement during the 2010 period.

Operating Expenses

The following table summarizes certain of our operating expenses per Mcfe for the periods presented:

	Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Lease operating	$	0.88	$	0.86	$	(0.02	)		(3	)%
Gathering, processing and transportation		0.35		0.31		(0.04	)		(11	)%
Production and ad valorem taxes		0.33		0.35		0.02			7	%
General and administrative		1.10		1.48		0.38			26	%
General and administrative excluding share-based
compensation and restructuring charges		0.94		0.99		0.05			5	%
Depreciation, depletion and amortization		2.84		2.99		0.15			5	%

Lease Operating

Lease operating expense increased on an absolute basis in the 2011 period due to higher maintenance and compression costs as well as higher workover costs incurred across the Company. In addition, certain other costs, including water disposal, were generally higher commensurate with higher production volumes during the 2011 period.

Gathering, Processing and Transportation

Production and Ad Valorem Taxes

On an absolute basis, production and ad valorem taxes increased commensurate with the higher production volumes during the 2011 period. As a percentage of product revenue, production and ad valorem taxes decreased to 5.6% during the 2011 period from 6.2% during the 2010 period due primarily to a production tax settlement with the State of Oklahoma.

General and Administrative

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

	Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Recurring general and administrative expenses	$	22,427	$	20,516	$	(1,911	)		(9	)%
Share-based compensation		3,809		4,689		880			19	%
Restructuring expenses		70		5,647		5,577			99	%
	$	26,306	$	30,852	$	4,546			15	%

Recurring general and administrative expenses increased primarily due to higher compensation and employee benefits charges offset partially by lower occupancy costs resulting from the organization restructuring that was substantially completed during 2010. In addition, professional fees and consulting charges decreased in the 2011 period. Share-based compensation charges decreased during the 2011 period due to a smaller participant base following the organization restructuring and a smaller number of awards that vested upon grant due to retirement eligibility. Organization restructuring expenses during the 2010 period include termination benefits and office and employee relocation costs as well as a $3.5 million charge related to the assignment of the lease of our former Kingsport, Tennessee office facility.

Exploration

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

	Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Dry hole costs	$	18,524	$	27	$	(18,497	)	NM
Geological and geophysical		6,137		4,485		(1,652	)		(37	)%
Unproved leasehold		22,557		9,491		(13,066	)		(138	)%
Other, primarily delay rentals		1,698		1,567		(131	)		(8	)%
	$	48,916	$	15,570	$	(33,346	)		(214	)%

The increase in dry hole costs is due primarily to three wells in the Mid-Continent region. The increase in amortization of unproved leaseholds is due primarily to significant acquisitions during 2010. Geological and geophysical costs reflect a larger exploration program in the 2011 period compared to the 2010 period.

Depreciation, Depletion and Amortization (DD&A)

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

	Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Depletion	$	65,049	$	58,544	$	(6,505	)		(11	)%
Depreciation - Oil and gas operations		1,237		1,292		55			4	%
Depreciation - Corporate		1,331		2,077		746			36	%
Amortization		262		221		(41	)		(19	)%
	$	67,879	$	62,134	$	(5,745	)		(9	)%

	DD&A Variance Due to
	Production			Rates		Total
Six months ended June 30, 2011 compared to 2010	$	(9,128	)	$	3,383	$	(5,745	)

Higher depletion during the 2011 period is commensurate with higher production volumes while the decrease in depreciation is primarily the result of the disposition of certain corporate assets during the prior year in connection with the 2010 organization restructuring. Our average depletion rate decreased to $2.73 per Mcfe for the 2011 period from $2.81 per Mcfe for the 2010 period.

Impairments

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

	Six Months Ended June 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Oil and gas properties	$	71,071	$	-	$	(71,071	)		NM
Other		-		1,124		1,124			NM
	$	71,071	$	1,124	$	(69,947	)		NM

During the six months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011. In July 2011, we executed an agreement to sell these properties.

Other

During the six months ended June 30, 2010, we recorded an initial loss on the disposition of our Gulf Coast properties in January 2010. Final purchase and sale adjustments were recorded during the fourth quarter of 2010.

Interest Expense

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

	Six Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Interest on borrowings and related fees	$	23,867		$	21,487		$	(2,380	)		(11	)%
Accretion of original issue discount		2,788			4,111			1,411			34	%
Amortization of debt issuance costs		1,962			2,109			59			3	%
Capitalized interest		(990	)		(717	)		273			38	%
Other, net		-			2			2			(100	)%
	$	27,627		$	26,992		$	(635	)		(2	)%

Loss on Extinguishment of Debt

Derivatives

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

	Six Months Ended June 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Oil and gas derivative unrealized derivative gain (loss)	$	(3,572	)	$	7,527		$	(11,099	)		(147	)%
Oil and gas derivative realized gain		10,877			17,825			(6,948	)		(39	)%
Interest rate swap unrealized gain		126			4,285			(4,159	)		(97	)%
Interest rate swap realized gain (loss)		898			(340	)		1,238			364	%
	$	8,329		$	29,297		$	(20,968	)		(72	)%

Cash received for settlements during the six months ended June 30, 2011 was $11.8 million compared to $17.5 million during the comparable period during 2010.

Other

Income Tax Expense

The effective tax rate for the six months ended June 30, 2011 was 35.6% compared to 38.2% for the 2010 period. Due to operating losses incurred during the first six months of 2011, we recognized an income tax benefit. In addition, the effective tax rate for the 2011 period includes a deferred tax asset valuation allowance due primarily to the inability to recognize a tax benefit for certain state net operating losses.

Discontinued Operations

The following table presents a summary of results of operations from discontinued operations for the periods presented:

	Six Months Ended June 30,
	2011		2010
Revenues	$	-	$	303,206

Income from discontinued operations before taxes	$	-	$	36,832
Income tax expense 1		-		(3,350	)
	$	-	$	33,482

1	Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to PVG's operations.

Gain on Sale of Discontinued Operations

In June 2010, we completed the sale of all of our remaining interest in PVG for $139.1 million net of offering costs and contributed 100% of the membership interests in PVG’s general partner to PVG thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $49.6 million, net of income tax effects of $35.1 million. Final sale adjustments were recorded during the fourth quarter of 2010.

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 proceeds from non-core asset sales. Our business strategy for the remainder of 2011 includes 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, the timing and magnitude of non-core asset sales and unanticipated expenditures such as acquisitions, we plan to fund the second half of our 2011 capital program with cash on hand, operating cash flows, proceeds from non-core asset sales, borrowings from our Revolver and supplemental issue of equity, as necessary.

As we continue to focus our 2011 development opportunities, primarily in liquids and oil-rich plays, including the Eagle Ford Shale in Texas, we continually assess our portfolio of properties with respect to maximizing our returns. Accordingly, we may consider selling certain non-core properties in order to redeploy our investments consistent with our current and longer-term objectives. We recently announced the execution of an agreement to sell our Arkoma Basin assets for approximately $30 million.

We replaced our previous revolving credit facility with the Revolver in August 2011. The Revolver provides for a $300 million revolving credit facility and matures in August 2016. The Revolver is governed by a borrowing base calculation and the availability may not exceed the lesser of the aggregate commitments or the borrowing base. We have the option to increase the aggregate commitments under the Revolver by up to an additional $300 million, not to exceed the borrowing base, upon the receipt of additional commitments from one or more lenders. The initial borrowing base is set at $400 million and will be redetermined on a semi-annual basis. Upon closing of the Arkoma sale transaction, the borrowing base under the Revolver will decrease by $20 million to $380 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions and includes a $20 million sublimit for the issuance of letters of credit.

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 through the use of derivatives, typically costless collar and swap 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 six months ended June 30, 2011, our commodity derivatives portfolio provided $11.2 million of cash inflows to offset lower than anticipated prices received for our current year natural gas production and resulted in payments of $0.3 million attributable to higher than anticipated prices received for our current year crude oil production. For the remainder of 2011, we have hedged approximately 59% of our estimated natural gas production, at a weighted average floor/swap price of $5.17 per MMBtu. In addition, we have hedged approximately 14% of our estimated crude oil production for the remainder of 2011, at weighted average floor and ceiling/swap prices of between $96.86 and $106.61 per barrel.

Cash Flows

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

	Six Months Ended June 30,
	2011			2010			Variance
Cash flows from operating activities	$	63,759		$	45,669		$	18,090
Cash flows from investing activities
Capital expenditures - property and equipment		(211,081	)		(168,081	)		(43,000	)
Proceeds from the sale of PVG units, net		-			139,120			(139,120	)
Proceeds from the sale of property and equipment and other, net		796			24,469			(23,673	)
Net cash used in investing activities		(210,285	)		(4,492	)		(205,793	)
Cash flows from financing activities
Dividends paid		(5,156	)		(5,131	)		(25	)
Proceeds from issuance of Senior Notes due 2019		300,000			-			300,000
Repurchase of Convertible Notes		(232,963	)		-			(232,963	)
Debt issuance costs paid		(6,559	)		-			(6,559	)
Proceeds from sale of PVG units, net		-			199,125			(199,125	)
Distributions received from discontinued operations		-			11,218			(11,218	)
Other, net		974			1,844			(870	)
Net cash provided by financing activities		56,296			207,056			(150,760	)
Net increase (decrease) in cash and cash equivalents	$	(90,230	)	$	248,233		$	(338,463	)

Cash Flows From Operating Activities

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

Cash flows from operating activities for the six months ended June 30, 2010	$	45,669
Variances due to:
Lower settlements from commodity derivatives portfolio		(6,948	)
Lower interest payments, net of amounts capitalized		1,270
Lower restructuring costs paid		2,606
Lower tax payments		3,246
Transaction costs paid in connection with extinguishment of debt		(2,433	)
Higher operating performance		20,349
Cash flows from operating activities for the six months ended June 30, 2011	$	63,759

Cash Flows From Investing Activities

Cash used in investing activities consisted of $211.1 million of capital expenditures, offset partially by the proceeds from the disposition of certain properties and equipment as well as an insurance settlement attributable to damages from a fire at one of our warehouse facilities. The 2010 period includes the receipt of proceeds from the sale of our remaining interests in PVG in June 2010, our former Gulf Coast properties in January 2010 and other non-core assets as an offset to our 2010 capital expenditures. As discussed below, in 2011 we anticipate total capital expenditures of approximately $370 million, exclusive of any additional acquisitions.

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

	Six Months Ended June 30,
	2011		2010
Oil and gas:
Development drilling	$	119,711	$	109,457
Exploration drilling		39,765		8,147
Seismic		6,137		4,485
Lease acquisitions, field projects and other		39,901		71,639
Pipeline and gathering facilities		3,571		738
		209,085		194,466
Other - Corporate		629		961
Total capital program costs	$	209,714	$	195,427

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

	Six Months Ended June 30,
	2011			2010
Total capital program costs	$	209,714		$	195,427
Less:
Exploration expenses
Seismic		(6,137	)		(4,485	)
Other, primarily delay rentals		(1,702	)		(1,264	)
Other		(1,576	)		-
Changes in accrued capitalized costs		9,692			(14,110	)
Property received as consideration in sale transaction 1		-			(8,204	)
Add:
Capitalized interest		990			717
Other		100			-
Total cash paid for capital expenditures	$	211,081		$	168,081

1	Represents property received in Mississippi in connection with the sale of our Gulf Coast properties.

Cash Flows From Financing Activities

Cash provided by financing activities during the 2011 period includes the issuance of $300 million of 2019 Senior Notes, offset substantially by the related transaction costs combined with the repurchase of approximately 98% of our Convertible Notes. In addition, we paid dividends of $5.2 million on our common stock, offset partially by the receipt of approximately $1 million from the exercise of stock options by employees.

During the 2010 period, we sold 11.25 million common units of PVG for proceeds of $199.1 million, net of offering costs, which reduced our limited partner interest in PVG to 22.6% at that time. Because we maintained a controlling financial interest in PVG until the final sale in June 2010, the proceeds from this transaction were reported as cash flows from financing activities. In addition, in the 2010 period, we received $11.2 million in distributions from PVG as well as $1.8 million from the exercise of stock options by employees.

Financial Condition

As of June 30, 2011, we had $30.7 million of cash on hand and approximately $160 million of unused borrowing capacity under our previous credit facility that was replaced by the Revolver in August 2011. Our initial available borrowing capacity under the Revolver is approximately $264 million. Our long-term debt as well as our compliance with the financial covenants as of June 30, 2011 under the previous credit facility is discussed below.

Debt and Credit Facility

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

	June 30,		December 31,
	2011		2010
Revolving credit facility	$	-	$	-
Senior Notes due 2016, net of discount (principal amount of $300,000)		293,009		292,487
Senior Notes due 2019		300,000		-
Convertible Notes due 2012, net of discount (principal amount of $4,915 and $230,000)		4,659		214,049
	$	597,668	$	506,536

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate (“LIBOR”), 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%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees will be 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.

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

2016 Senior Notes. The 10.375% Senior Unsecured 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 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 semi-annually in arrears 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 reflecting 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. 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.

In connection with the sale of the Convertible Notes, we entered into convertible note hedge transactions, or the Note Hedges, with respect to shares of our common stock with affiliates of certain of the underwriters of the Convertible Notes (collectively, the “Option Counterparties”). The Note Hedges cover, subject to anti-dilution adjustments, the net shares of our common stock that would be deliverable to converting noteholders in the event of a conversion of the Convertible Notes.

We also entered into separate warrant transactions, or Warrants, whereby we sold to the Option Counterparties warrants to acquire, subject to anti-dilution adjustments, approximately 3,982,680 shares of our common stock at an exercise price of $74.25 per share. Upon exercise of the Warrants, we will deliver shares of our common stock equal in value to the excess of the then market price over the strike price of the Warrants.

If the market value per share of our common stock at the time of conversion of the Convertible Notes is above the strike price of the Note Hedges, the Note Hedges entitle us to receive from the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount) based on the excess of the then current market price of our common stock over the strike price of the Note Hedges. Additionally, if the market price of our common stock at the time of exercise of the Warrants exceeds the strike price of the Warrants, we will owe the Option Counterparties net shares of our common stock (and cash for any fractional share cash amount), not offset by the Note Hedges, in an amount based on the excess of the then current market price of our common stock over the strike price of the Warrants.

Interest Rate Swaps. In December 2009, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the 2016 Senior Notes.

The following table describes our interest rate swap agreement as of June 30, 2011:

	Notional		Swap Interest Rates
Term	Amounts		Pay	Receive
Through June 2013	$	100,000	3-month LIBOR + 8.175%		10.375	%

Covenant Compliance

Our previous credit facility required us to maintain certain financial covenants as follows:

Total debt to EBITDAX, each as defined in the previous credit facility, for any four consecutive quarters may not exceed 4.0 to 1.0 reducing to 3.5 to 1.0 for periods ending on or after September 30, 2011. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments, other non-cash charges or losses and the amount of cash distributions received from PVG and Penn Virginia Resource Partners, L.P.

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 previous credit facility.

As of June 30, 2011 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these covenants of our previous credit facility.

The following table summarizes the actual results of our financial covenant compliance under our previous credit facility for the period ended June 30, 2011:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.0 to 1	3.1 to 1
Current ratio	> 1.0 to 1	4.2 to 1

The Revolver has a current ratio financial covenant identical to our previous credit facility. The leverage ratio financial covenant, which is initially effective for the period ended September 30, 2011, provides that the ratio of total net 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 after June 30, 2013.

In the event that we would be in default of a covenant under the Revolver, we could request the banks for a waiver of the covenant. 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 the 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 2011, we anticipate making capital expenditures, excluding any potential acquisitions, of approximately $370 million. The capital expenditures have been and will continue to be funded primarily by cash on hand supplemented by operating cash flows and, as necessary, proceeds from non-core asset sales, borrowing under the Revolver and supplemental issues of equity, as necessary. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on 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 2011, we expect to allocate the capital expenditures as follows: Eagle Ford Shale (60%), Marcellus Shale (11%), Mid-Continent region (Anadarko Basin) (23%) and all other areas (6%). This allocation includes approximately 82% for development and exploratory drilling, 12% for leasehold acquisition and 6% for seismic and other projects. We anticipate that we will allocate approximately 83% of 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 that 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 including the plugging of abandoned wells. As of June 30, 2011, we have recorded asset retirement obligations of $7.3 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 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, 2010 and remained unchanged as of June 30, 2011.

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 risk to which we are exposed is commodity price risk. As discussed below, we engage in price risk management activities with respect to managing our commodity price risk, which exposes us to counterparty risk with financial institutions with whom we enter into price risk management activities.

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 swaps, costless collars and three-way collars) 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.

In the six months ended June 30, 2011, we reported net commodity derivative gains of $7.3 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 June 30, 2011:

		Average
		Volume Per		Weighted Average Price				Fair Value
	Instrument	Day		Floor/Swap		Ceiling		Asset		Liability
		(in MMBtu)
Natural Gas:
Third quarter 2011	Costless collars		30,000	$	4.83	$	6.00	$	1,615	$	-
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50		2,703		-
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		2,349		-
Third quarter 2011	Swaps		40,000	$	5.06				2,532		-
Fourth quarter 2011	Swaps		10,000	$	5.01				399		-
First quarter 2012	Swaps		10,000	$	5.10				250		-
Second quarter 2012	Swaps		20,000	$	5.31				1,098		-
Third quarter 2012	Swaps		20,000	$	5.31				935		-
Fourth quarter 2012	Swaps		10,000	$	5.10				76		-

Crude Oil:		(barrels)
Third quarter 2011	Costless collars		360	$	80.00	$	103.30		-		24
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		-		91
First quarter 2012	Costless collars		500	$	100.00	$	120.00		317		-
Second quarter 2012	Costless collars		500	$	100.00	$	120.00		300		-
Third quarter 2012	Costless collars		500	$	100.00	$	120.00		292		-
Fourth quarter 2012	Costless collars		500	$	100.00	$	120.00		295		-
Third quarter 2011	Swaps		500	$	109.00				591		-
Fourth quarter 2011	Swaps		500	$	109.00				520		-
								$	14,272	$	115

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
	Increase			Decrease
Effect on the fair value of natural gas derivatives	$	(13.1	)	$	13.8
Effect on the fair value of crude oil derivatives	$	(3.1	)	$	2.5
Effect on 2011 operating income, excluding natural gas derivatives	$	(15.8	)	$	15.8
Effect on 2011 operating income, excluding crude oil derivatives	$	(13.2	)	$	13.2

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2011. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of June 30, 2011, 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	Amendment One to the Penn Virginia Corporation Amended and Restated Non-Employee Directors Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on May 6, 2011).

10.2	Amendment No. 1 to the Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on May 6, 2011).

10.3	First Amendment and Waiver of Credit Agreement dated as of April 5, 2011 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 April 5, 2011).

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: August 4, 2011	By:	/s/ Steven A. Hartman
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer

Date: August 4, 2011	By:	/s/ Joan C. Sonnen
		Joan C. Sonnen
		Vice President and Controller