Unassociated Document

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

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 volumes compared to the 2010 period.

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 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 below, is approximately $264 million.

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

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.

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.

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. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of June 30, 2011.

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

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

Large accelerated filer	x	Accelerated filer	¨

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

	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

	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

	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

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

	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

		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

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

	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

	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		$	-

	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

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