Exhibit 99.1

Penn Virginia Corporation

Four Radnor Corporate Center, Suite 200, 100 Matsonford Road, Radnor, PA 19087

FOR IMMEDIATE RELEASE

Contact:	James W. Dean
	Vice President, Corporate Development
	Ph: (610) 687-7531 Fax: (610) 687-3688
	E-Mail: invest@pennvirginia.com

PENN VIRGINIA CORPORATION

ANNOUNCES SECOND QUARTER 2010 RESULTS

COMPLETES TRANSITION TO PURE-PLAY EXPLORATION AND PRODUCTION COMPANY

CAPITAL REDEPLOYED TO LIQUIDS RICH PLAYS

PRODUCTION GROWTH RESUMING

RADNOR, PA (BusinessWire) August 4, 2010 – Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended June 30, 2010 and provided an update of full-year 2010 guidance.

Second Quarter 2010 Highlights

Second quarter 2010 results, with comparisons to second quarter 2009 results, included the following:

• Quarterly oil and gas production of 10.5 billion cubic feet of natural gas equivalent (Bcfe), or 115.1 million cubic feet of natural gas equivalent (MMcfe) per day, as compared to 12.3 Bcfe, or 134.7 MMcfe per day, pro forma to exclude production from Gulf Coast assets sold in January 2010;

• Operating loss of $20.9 million, as compared to a loss of $37.6 million;

• Net income attributable to PVA of $31.1 million, or $0.68 per diluted share, which included a pretax gain on the sale of Penn Virginia GP Holdings, L.P. (NYSE: PVG) of $84.7 million ($49.6 million, or $1.08 per diluted share, after tax), as compared to a loss of $22.2 million, or $0.52 per diluted share;

• Net loss from continuing operations of $21.1 million, or $0.46 per diluted share, as compared to a loss of $26.2 million, or $0.61 per diluted share; and

• Adjusted net loss attributable to PVA, a non-GAAP measure which excluded the effects of the gain on sale of discontinued operations, non-cash change in derivatives fair value, impairments, drilling rig standby charges, restructuring costs, and gains or losses that affect comparability to the prior year period, of $9.4 million, or $0.21 per diluted share, as compared to a loss of $7.1 million, or $0.17 per diluted share.

The operating loss, net loss from continuing operations and net income attributable to PVA in the second quarter of 2010, as reported above, include restructuring costs of $4.2 million related to the divestiture of PVA’s remaining interests in PVG.

Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the financial tables later in this release.

Management Comment

A. James Dearlove, President and CEO said, “Penn Virginia completed the transition to a “pure play” exploration and production (E&P) company in June, when we sold our remaining interests in PVG. We are redeploying a portion of the PVG sale proceeds to accelerate growth in our near-term production in the oil and liquids rich Granite Wash and horizontal Cotton Valley plays. We are also adding acreage to our core holdings in the Granite Wash and Marcellus Shale plays. Penn Virginia is in a position to make these investments, while maintaining our financial flexibility, as a result of having raised over $825 million of capital since May 2009 through the issuances of debt and equity securities as well as the sales of non-core assets.

“Specifically, of the $70 million increase in the midpoint of 2010 capital expenditures guidance, approximately $30 million will be for drilling additional Granite Wash and horizontal Cotton Valley wells, which should benefit our production beginning in the fourth quarter of 2010. The remaining $40 million of the capital expenditures increase will be dedicated primarily to expanding our Granite Wash and Marcellus Shale land positions, including previously announced Marcellus Shale leasehold acquisitions, and infrastructure.

“Compared to the prior year quarter, we experienced a decline in oil and gas production resulting primarily from our decision to suspend drilling in the latter part of 2009. Sequentially, our quarterly production was up only slightly as we continued to experience equipment-related delays in well completions in East Texas and the Granite Wash during the early part of the second quarter of 2010. The delays led to an approximate 0.7 Bcfe shortfall in production compared to our expectations for the second quarter. However, primarily as a result of strong well results from these two areas, in June we experienced our fourth best month of pro forma production (133.0 MMcfe per day) and have increased production guidance in the second half of 2010 to levels significantly higher than the first half results.

“For the second half of 2010, we have hedged approximately 50 percent of the midpoint of our estimated natural gas production, at weighted average floor and ceiling prices of $5.70 and $7.85 per MMBtu.”

Second Quarter 2010 Financial and Operational Results

Production in the second quarter of 2010 was approximately 10.5 Bcfe, or 115.1 MMcfe per day, 15 percent less than the pro forma 12.3 Bcfe, or 134.7 MMcfe per day, in the second quarter of 2009 and five percent more than the pro forma 10.0 Bcfe, or 111.6 MMcfe per day, in the first quarter of 2010. The year-over-year decrease in was due to natural production declines, the effects of significantly reduced drilling activity in late 2009 and, to a lesser extent, by well completion delays due to difficulty in obtaining stimulation equipment in East Texas and in the Granite Wash. See our separate operational update news release dated August 4, 2010 for a more detailed discussion of operations.

Our realized natural gas price, prior to the impact of derivatives, during the second quarter of 2010 was $4.25 per thousand cubic feet (Mcf), 22 percent higher than the $3.49 per Mcf price in the second quarter of 2009, but 24 percent lower than the $5.60 per Mcf price in the first quarter of 2010. Our realized oil price, prior to the impact of derivatives, during the second quarter of 2010 was $73.58 per barrel, 34 percent higher than the $55.00 per barrel price in the second quarter of 2009, but one percent lower than the $74.44 per barrel price in the first quarter of 2010. Our realized natural gas liquids (NGLs) price during the second quarter of 2010 was $35.03 per barrel, 13 percent higher than the $30.97 per barrel price in the second quarter of 2009, but 22 percent lower than the $44.64 per barrel price in the first quarter of 2010. Adjusting for oil and gas hedges, our effective natural gas price during the second quarter of 2010 was $5.24 per Mcf and our effective oil price was $71.89 per barrel, or an increase of $0.99 per Mcf and decrease of $1.69 per barrel, respectively, over the realized prices.

The operating loss of $20.9 million was a $16.7 million improvement over the operating loss of $37.6 million in the prior year quarter. The decrease in operating loss was due to a 21 percent increase in the realized gas equivalent commodity price, from $4.13 to $5.00 per Mcfe, and a $6.4 million decrease in other operating expenses, which include impairments, drilling rig standby charges, restructuring costs and loss on the sale of assets, partially offset by the effects of the production decrease.

As discussed below, second quarter 2010 direct operating expenses increased $1.8 million, or six percent, to $29.7 million as compared to $27.9 million in the second quarter of 2009.

• Lease operating expenses decreased by $2.3 million, or 20 percent, to $9.2 million, or $0.87 per Mcfe produced, from $11.4 million, or $0.84 per Mcfe produced, resulting primarily from the production decrease;

• Gathering, processing and transportation expenses decreased by $0.1 million, or three percent, to $3.3 million, or $0.32 per Mcfe produced, from $3.4 million, or $0.25 per Mcfe produced, resulting primarily from the production decrease;

• Production and ad valorem taxes decreased by $0.2 million, or seven percent, to $3.1 million, or 5.9 percent of total oil and gas revenues, from $3.3 million, or 6.0 percent of total oil and gas revenues, due to the revenue decrease; and

• General and administrative expense increased by $4.4 million to $14.2 million from $9.8 million, resulting primarily from $4.2 million of restructuring costs related to the divestiture of PVG.

Exploration expense decreased 45 percent to $9.5 million in the second quarter of 2010, as compared to $17.5 million in the prior year quarter, due primarily to $6.7 million of drilling rig standby charges in the prior year quarter.

Depreciation, depletion and amortization expenses decreased by $8.8 million, or 22 percent, to $32.1 million, or $3.06 per Mcfe, in the second quarter of 2010 from $40.9 million, or $3.02 per Mcfe, in the prior year quarter, as a result of the production decrease.

Full-Year 2010 Guidance Update

Full-year 2010 guidance highlights are as follows:

• Full-year 2010 production guidance of 47.0 to 50.0 Bcfe, which remains unchanged as compared to previous guidance despite the second quarter production shortfall;

• Increased third quarter production guidance to a range of 12.2 to 13.5 Bcfe, from a previous guidance range of 12.0 to 13.2 Bcfe;

• Increased fourth quarter production guidance to a range of 14.0 to 15.7 Bcfe, from a previous guidance range of 14.0 to 15.0 Bcfe;

• For the second half of 2010, the production guidance range of 26.2 to 29.2 Bcfe, or 142.3 to 158.6 MMcfe per day, is 24 to 38 percent higher than the 20.8 Bcfe, or 115.0 MMcfe per day, of first half reported production; and

• Increased oil and gas capital expenditures guidance to a range of $450 to $490 million from a range of $375 to $425 million of previous guidance, reflecting up to approximately $30 million of additional non-operated drilling in the Granite Wash and operated drilling in the horizontal Cotton Valley, as well as up to approximately $40 million of additional land acquisition, facilities and seismic, primarily in the Granite Wash and Marcellus Shale plays.

Our currently anticipated oil and gas capital expenditures for 2010 include $325 to $350 million for drilling and completion activity, and $100 to $110 million for land acquisition. The drilling capital expenditures include:

• approximately 65 percent for the oil and liquids rich Granite Wash and horizontal Cotton Valley; and

• approximately 20 percent for drilling in the Haynesville and Marcellus Shales.

The land acquisition expenditures include:

• approximately 60 percent for the Marcellus Shale; and

• approximately 25 percent for the Granite Wash.

See the Guidance Table included in this release for guidance estimates for full-year 2010. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Capital Resources and Liquidity, Interest Expense and Impact of Derivatives

As of June 30, 2010, we had outstanding borrowings of $530.0 million ($502.5 million carrying value), consisting of $300 million ($292.2 million carrying value) of senior unsecured notes due 2016 and $230.0 million ($210.3 million carrying value) of convertible senior subordinated notes due 2012, with no borrowings against our revolving credit facility. Net of cash and equivalents of $327.3 million, our net indebtedness at June 30, 2010 was $175.2 million.

Currently, we have approximately $735 million of financial liquidity, excluding cash flows from operating activities, comprised of cash on hand ($315 million), committed availability under our revolving credit facility ($300 million) and an additional $120 million of borrowing base availability. Together with ongoing cash flows from operating activities, supplemented by natural gas and crude oil hedges, we expect this financial liquidity to be sufficient to fund our anticipated capital needs for the remainder of 2010 and 2011.

Consolidated interest expense increased to $13.3 million in the second quarter of 2010 from $8.7 million in the second quarter of 2009. The increase was due primarily to a $3.5 million increase in cash interest expense from $7.1 million in the prior year quarter to $10.6 million in the second quarter of 2010. The cash interest expense increased due to a higher interest rate on the senior unsecured notes we issued in June 2009, partially offset by lower outstanding balances on our revolving credit facility. Other non-cash components of interest expense increased by $1.1 million, from $1.6 million in the prior year quarter to $2.7 million in the second quarter of 2010, due primarily to increases in amortization of debt issuance costs and losses on interest rate derivatives.

Due to fluctuations in commodity prices during the second quarter of 2010, derivatives expense was $0.6 million in the second quarter of 2010 as compared to derivatives income of $2.8 million in the prior year quarter. Second quarter 2010 cash settlements of our derivatives resulted in net cash receipts of $9.1 million, as compared to $15.7 million of net cash receipts in the prior year quarter.

Second Quarter 2010 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss second quarter 2010 financial and operational results, is scheduled for Thursday, August 5, 2010 at 3:00 p.m. ET. Prepared remarks by A. James Dearlove, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-630-9986 five to ten minutes before the scheduled start of the conference call (use the passcode 4650813), or via webcast by logging on to our website, www.pennvirginia.com, at least 15 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available for two weeks beginning approximately 24 hours after the call. The replay can be accessed by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 4650813. In addition, an on-demand replay of the webcast will also be available for two weeks at our website beginning approximately 24 hours after the webcast.

******

Penn Virginia Corporation (NYSE: PVA) is an independent natural gas and oil company focused on the exploration, acquisition, development and production of reserves in onshore regions of the U.S., including East Texas, the Mid-Continent region, the Appalachian Basin and Mississippi.

For more information, please visit our website at www.pennvirginia.com.

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. 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, or NGLs, and crude oil; our ability to access external sources of capital; uncertainties relating to the occurrence and success of capital-raising transactions, including securities offerings and asset sales; reductions in the borrowing base under our revolving credit facility; our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired; any impairment write-downs of our reserves or assets; reductions in our anticipated capital expenditures; the relationship between natural gas, NGL and crude oil; the projected demand for and supply of natural gas, NGLs and crude oil; the availability and costs of required drilling rigs, production equipment and materials; our ability to obtain adequate pipeline transportation capacity for our oil and gas production; competition among producers in the oil and natural gas industry generally; the extent to which the amount and quality of actual production of our oil and natural gas differ from estimated proved oil and gas reserves; operating risks, including unanticipated geological problems, incidental to our business; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our oil and natural gas production; environmental risks affecting the drilling and producing of oil and gas wells; the timing of receipt of necessary governmental permits by us; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters; risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2009.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2009. 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.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS - unaudited

(in thousands, except per share data)

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Revenues
Natural gas	$	38,819		$	39,830		$	86,807		$	92,651
Crude oil		10,875			11,825			24,721			18,153
Natural gas liquids (NGLs)		2,662			4,336			7,528			7,706
Gain on sale of property and equipment		125			—			336			—
Other		807			(88	)		1,774			1,967
		53,288			55,903			121,166			120,477
Expenses
Lease operating		9,155			11,405			17,892			23,421
Gathering, processing and transportation		3,309			3,409			6,540			6,156
Production and ad valorem taxes		3,105			3,336			7,375			7,463
General and administrative (excluding equity compensation) (a)		14,159			9,799			26,163			18,630
Total direct operating expenses		29,728			27,949			57,970			55,670
Equity-based compensation (b)		1,668			2,351			4,689			4,955
Exploration		9,541			10,733			15,570			22,181
Exploration - drilling rig standby charges (c)		—			6,739			—			16,603
Depreciation, depletion and amortization		32,105			40,901			62,134			81,776
Impairments		1,124			3,279			1,124			4,475
Other		—			1,599			465			1,599
Total operating expenses		74,166			93,551			141,952			187,259
Operating loss		(20,878	)		(37,648	)		(20,786	)		(66,782	)
Other income (expense)
Interest expense		(13,321	)		(8,681	)		(26,992	)		(15,567	)
Derivatives		(580	)		2,786			29,297			20,202
Other		517			6			1,763			1,250
Loss from continuing operations before income taxes		(34,262	)		(43,537	)		(16,718	)		(60,897	)
Income tax benefit		13,165			17,320			6,387			24,048
Net loss from continuing operations		(21,097	)		(26,217	)		(10,331	)		(36,849	)
Income from discontinued operations, net of tax		21,308			10,379			33,482			17,460
Gain on sale of discontinued operations, net of tax		49,612			—			49,612			—
Net income (loss)		49,823			(15,838	)		72,763			(19,389	)
Less net income attributable to noncontrolling interests in discontinued operations		(18,744	)		(6,345	)		(28,090	)		(10,003	)
Income (loss) attributable to PVA	$	31,079		$	(22,183	)	$	44,673		$	(29,392	)
Income (loss) per share attributable to PVA - Basic
Continuing operations	$	(0.46	)	$	(0.61	)	$	(0.23	)	$	(0.87	)
Discontinued operations		0.06			0.09			0.12			0.18
Gain on sale of discontinued operations		1.08			—			1.09			—
Net income (loss) attributable to PVA	$	0.68		$	(0.52	)	$	0.98		$	(0.69	)
Income (loss) per share attributable to PVA - Diluted
Continuing operations	$	(0.46	)	$	(0.61	)	$	(0.23	)	$	(0.87	)
Discontinued operations		0.06			0.09			0.12			0.18
Gain on sale of discontinued operations		1.08			—			1.09			—
Net income (loss) attributable to PVA	$	0.68		$	(0.52	)	$	0.98		$	(0.69	)
Weighted average shares outstanding, basic		45,539			42,798			45,508			42,422
Weighted average shares outstanding, diluted		45,790			42,798			45,767			42,422
	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Production
Natural gas (MMcf)		9,132			11,422			17,700			23,224
Crude oil (MBbls)		148			215			334			386
NGLs (MBbls)		76			140			185			287
Total natural gas, crude oil and NGL production (MMcfe)		10,475			13,552			20,813			27,262
Prices
Natural gas ($ per Mcf)	$	4.25		$	3.49		$	4.90		$	3.99
Crude oil ($ per Bbl)	$	73.58		$	55.00		$	74.09		$	47.03
NGLs ($ per Bbl)	$	35.03		$	30.97		$	40.66		$	26.85
Prices - Adjusted for derivative settlements
Natural gas ($ per Mcf)	$	5.24		$	4.79		$	5.92		$	5.27
Crude oil ($ per Bbl)	$	71.89		$	61.42		$	73.78		$	54.10
NGLs ($ per Bbl)	$	35.03		$	30.97		$	40.66		$	26.85

(a) Includes restructuring costs of $4.2 million and $5.6 million for the three and six months ended June 30, 2010, respectively.

(b) Our equity-based compensation expense includes our stock option expense and the amortization of restricted stock and restricted stock units related to employee awards in accordance with accounting guidance for share-based payments.

(c) Drilling rig standby charges represent fees paid in connection with the deferral of drilling associated with contractually committed rigs and frac tank rentals.

PENN VIRGINIA CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

	June 30, 2010		December 31, 2009
Assets
Current assets	$	425,150	$	192,134
Current assets of discontinued operations		—		107,108
Net property and equipment		1,598,504		1,479,452
Other assets		27,982		26,470
Noncurrent assets of discontinued operations		—		1,083,343
Total assets	$	2,051,636	$	2,888,507
Liabilities and shareholders’ equity
Current liabilities	$	210,817	$	75,620
Current liabilities of discontinued operations		—		77,915
Revolving credit facility		—		—
Senior notes		292,251		291,749
Convertible notes		210,287		206,678
Other liabilities and deferred taxes		303,467		351,409
Noncurrent liabilities of discontinued operations		—		647,137
PVA shareholders’ equity		1,034,814		908,088
Noncontrolling interests in discontinued operations		—		329,911
Total shareholders’ equity		1,034,814		1,237,999
Total liabilities and shareholders’ equity	$	2,051,636	$	2,888,507

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Cash flows from operating activities
Net income (loss)	$	49,823		$	(15,838	)	$	72,763		$	(19,389	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Net income from discontinued operations		(22,877	)		(13,079	)		(36,832	)		(22,326	)
Gain on sale of discontinued operations		(84,740	)		—			(84,740	)		—
Depreciation, depletion and amortization		32,105			40,901			62,134			81,776
Impairments		1,124			3,279			1,124			4,475
Derivative contracts:
Total derivative gains		581			(2,283	)		(29,297	)		(19,699	)
Cash receipts to settle derivatives		9,050			15,668			17,484			31,980
Deferred income taxes		1,267			(14,166	)		(7,733	)		(18,800	)
Dry hole and unproved leasehold expense		4,462			9,379			9,491			19,883
Noncash interest expense		3,074			2,318			6,220			4,395
Other		1,449			6,264			4,383			8,953
Changes in operating assets and liabilities		19,606			(36,361	)		30,672			(5,806	)
Net cash provided by (used in) operating activities		14,924			(3,918	)		45,669			65,442
Cash flows from investing activities
Capital expenditures - property and equipment		(103,589	)		(44,288	)		(168,081	)		(165,268	)
Proceeds from the sale of PVG units, net (a)		139,120			—			139,120			—
Proceeds from the sale of property, plant and equipment, net		4			5,250			23,277			5,239
Other		1,192			11			1,192			11
Net cash (used in) provided by investing activities		36,727			(39,027	)		(4,492	)		(160,018	)
Cash flows from financing activities
Dividends paid		(2,575	)		(2,370	)		(5,131	)		(4,719	)
Distributions received from discontinued operations		3,566			11,531			11,218			23,064
Repayments of bank borrowings		—			—			—			(7,542	)
Repayment of borrowings		—			(320,000	)		—			(262,000	)
Proceeds from the issuance of Senior notes, net		—			291,009			—			291,009
Proceeds from the issuance of common stock, net		—			64,835			—			64,835
Proceeds from the sale of PVG units, net (a)		22,125			—			199,125			—
Debt issuance costs paid		—			(8,827	)		—			(8,827	)
Other		1,232			—			1,844			—
Net cash provided by financing activities		24,348			36,178			207,056			95,820
Net increase (decrease) in cash and cash equivalents		75,999			(6,767	)		248,233			1,244
Cash and cash equivalents - beginning of period		251,251			8,011			79,017			—
Cash and cash equivalents - end of period	$	327,250		$	1,244		$	327,250		$	1,244

(a) Net proceeds from the sale of PVG units included in investing activities is attributable to the sale of the final tranche of PVG units, which resulted in the loss of control and deconsolidation of PVG from our financial statements. Net proceeds from the sale of PVG units included in financing activities represents proceeds received from sales of our ownership interests in PVG while we still maintained control.

PENN VIRGINIA CORPORATION

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

	Three months ended June 30,						Six months ended June 30,
	2010			2009			2010			2009
Reconciliation of GAAP “Net income (loss) attributable to PVA” to Non-GAAP “Net income (loss) attributable to PVA, as adjusted”
Net income (loss) attributable to PVA	$	31,079		$	(22,183	)	$	44,673		$	(29,392	)
Adjustments for derivatives:
Derivative (gains) losses included in net income		581			(2,283	)		(29,297	)		(19,699	)
Cash receipts to settle derivatives		9,050			15,668			17,484			31,980
Adjustment for drilling rig standby charges		—			6,739			—			16,603
Adjustment for impairments		1,124			3,279			1,124			4,475
Adjustment for restructuring costs		4,170			—			5,647			—
Adjustment for net loss (gain) on sale of assets		(125	)		1,599			129			1,599
Adjustment for gain on sale of discontinued operations		(84,740	)		—			(84,740	)		—
Impact of adjustments on income taxes		29,441			(9,946	)		37,005			(13,805	)
	$	(9,420	)	$	(7,127	)	$	(7,975	)	$	(8,239	)
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes		—			(21	)		(28	)		(34	)
Net loss attributable to PVA, as adjusted (a)	$	(9,420	)	$	(7,148	)	$	(8,003	)	$	(8,273	)
Net loss attributable to PVA, as adjusted, per share, diluted	$	(0.21	)	$	(0.17	)	$	(0.17	)	$	(0.20	)

(a) Net income (loss) attributable to PVA, as adjusted, represents net income (loss) attributable to PVA adjusted to exclude the effects of non-cash changes in the fair value of derivatives, drilling rig standby charges, impairments, restructuring costs, gains and losses on the sale of assets, the gain on the sale of PVG (discontinued operations) and net income of Penn Virginia Resource Partners, L.P. (PVR) allocated to unvested PVR restricted units awarded as equity compensation that are held until vesting. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. We use this information for comparative purposes within our industry. Net income (loss) attributable to PVA, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income attributable to PVA.

PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited

(dollars in millions except where noted)

We are providing the following guidance regarding financial and operational expectations for full-year 2010.

	First Quarter 2010			Second Quarter 2010		YTD 2010		Full-Year 2010 Guidance
Production:
Natural gas (Bcf) - see Note to Guidance Table		8.6		9.1		17.7		36.4 - 38.8
Crude oil (MBbls) - see Note to Guidance Table		186		148		334		875 - 925
NGLs (MBbls)		109		76		185		900 - 950
Equivalent production (Bcfe)		10.3		10.5		20.8		47.0 - 50.0
Equivalent daily production (MMcfe per day)		114.9		115.1		115.0		128.8 - 137.0
Operating expenses:
Lease operating ($ per Mcfe)*	$	0.85		0.87		0.86		0.75 - 0.80
Gathering, processing and transportation costs ($ per Mcfe)*	$	0.31		0.32		0.31		0.30 - 0.32
Production and ad valorem taxes (percent of oil and gas revenues)*		6.4	%	5.9	%	6.2	%	6.5% - 7.0	%
General and administrative*	$	12.0		14.2		26.2		42.0 - 46.0
Equity-based compensation	$	3.0		1.7		4.7		8.0 - 9.0
Exploration	$	6.0		9.5		15.5		42.0 - 46.0
Depreciation, depletion and amortization ($ per Mcfe)	$	2.90		3.06		2.99		2.95 - 3.05
Interest expense	$	13.7		13.3		27.0		45.0 - 50.0
Capital expenditures:
Development drilling	$	37.9		71.6		109.5		275.0 - 295.0
Exploratory drilling	$	3.7		4.4		8.1		50.0 - 55.0
Pipeline, gathering, facilities	$	0.2		0.5		0.7		9.0 - 11.0
Seismic	$	0.4		4.1		4.5		16.0 - 19.0
Lease acquisitions, field projects and other	$	35.5		36.1		71.6		100.0 - 110.0
Total oil and gas capital expenditures	$	77.7		116.7		194.4		450.0 - 490.0
End of period debt outstanding	$	500.5		502.5		502.5
Effective interest rate		10.9	%	11.0	%	11.0	%
Income tax benefit rate		38.6	%	38.4	%	38.2	%
Cash distributions received from PVG and PVR	$	7.7		3.5		11.2		11.2 - 11.2

* - Prior to the sale of PVG, these line items were combined for guidance purposes and shown as “Cash operating expenses” with the Corporate G&A expenses reflected separately. With the sale of PVG, PVA no longer will report segments. As such, we believe that a more detailed breakdown of these expenses, including the combination of regional and corporate G&A, will provide useful guidance information to investors.

These estimates are meant to provide guidance only and are subject to change as PVA’s operating environment changes.

PENN VIRGINIA CORPORATION

GUIDANCE TABLE - unaudited - (continued)

Note to Guidance Table:

The following table shows our current derivative positions as of June 30, 2010:

			Weighted Average Price
	Instrument Type	Average Volume Per Day	Additional Put Option	Floor	Ceiling
Natural gas:		(MMBtu)		($ per MMBtu)
Third quarter 2010	Costless collars	30,000		5.33	8.02
Third quarter 2010	Swaps	30,000		6.17
Fourth quarter 2010	Costless collars	50,000		5.65	8.77
First quarter 2011	Costless collars	50,000		5.65	8.77
Second quarter 2011	Costless collars	30,000		5.67	7.58
Third quarter 2011	Costless collars	30,000		5.67	7.58
Fourth quarter 2011	Costless collars	20,000		6.00	8.50
First quarter 2012	Costless collars	20,000		6.00	8.50
Second quarter 2012	Swaps	10,000		5.52
Third quarter 2012	Swaps	10,000		5.52
Crude oil:		(barrels)		($ per barrel)
Third quarter 2010	Costless collars	500		60.00	74.75
Fourth quarter 2010	Costless collars	500		60.00	74.75
First quarter 2011	Costless collars	425		80.00	101.50
Second quarter 2011	Costless collars	425		80.00	101.50
Third quarter 2011	Costless collars	360		80.00	103.30
Fourth quarter 2011	Costless collars	360		80.00	103.30

We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, operating income for the remainder of 2010 would increase or decrease by approximately $19 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, operating income for 2010 would increase or decrease by approximately $4 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.