Penn Virginia Corporation Announces Second Quarter 2009 Results

Penn Virginia Corporation (NYSE:PVA) today reported financial and operational results for the three months ended June 30, 2009 and provided an update of full-year 2009 guidance.

Second Quarter 2009 Highlights

Second quarter 2009 results, with comparisons to second quarter 2008 results, included the following:

• Quarterly oil and gas production of 148.9 million cubic feet of natural gas equivalent (MMcfe) per day, or 13.6 billion cubic feet of natural gas equivalent (Bcfe), an 18 percent increase as compared to oil and gas production of 125.7 MMcfe per day, or 11.4 Bcfe;
• Operating cash flow, a non-GAAP (generally accepted accounting principles) measure, of $68.7 million as compared to record operating cash flow of $136.0 million in the prior year quarter;
• Adjusted net loss, a non-GAAP measure which excludes the effects of the non-cash change in derivatives fair value, drilling rig standby charges and impairments that affect comparability to the prior year period, of $6.0 million, or $0.14 per diluted share, as compared to record adjusted net income of $48.7 million, or $1.17 per diluted share, in the prior year quarter; and
• Net loss of $22.2 million, or $0.52 per diluted share, as compared to net loss of $4.5 million, or $0.11 per diluted share.

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 Chief Executive Officer, said, "Although declines in commodity prices impacted our financial results, we are pleased with our second quarter 2009 operational results. As detailed in our July 27 operational update, weak natural gas prices have caused us to curtail our drilling activity substantially. However, as a result of strong performance from 2008 and early 2009 drilling in our Granite Wash, Lower Bossier (Haynesville) Shale and Selma Chalk core plays, our second quarter production levels were only two percent lower than the record production achieved in the first quarter of 2009. As a result of our strong second quarter and first half results, we have kept our production guidance unchanged, with slight year-over-year production growth in 2009.

"Our commodity price hedges provided cash flow protection, increasing second quarter effective price realizations from $3.49 per Mcf to $4.78 pre Mcf for natural gas and from $55.00 per barrel to $61.42 per barrel for oil. For the second half of 2009, we have hedged approximately 85 percent of our estimated natural gas production at average respective floor and ceiling prices of $6.42 and $7.79 per million British thermal units (MMBtu), and 70 percent of our estimated crude oil production at average floor and ceiling prices of approximately $80 and $120 per barrel. For 2010, we have hedged approximately 60 percent of our estimated natural gas production at average respective floor and ceiling prices of $6.09 and $8.19 per MMBtu, and 35 percent of our estimated crude oil production at average respective floor and ceiling prices of approximately $60 and $75 per barrel. In addition to the cash flow support our hedges have provided, our unit cash costs have continued to improve, including a 22 percent reduction from the prior year quarter and in line with the first quarter of 2009.

"During the second quarter of 2009, we raised approximately $365 million of capital, including $300 million of senior notes due 2016 and $65 million of common equity. As a result, we have substantially improved our financial liquidity, with almost $300 million of unused availability on our revolving credit facility. We are now positioned to exploit our ample inventory of drilling locations for growth in the coming years from both existing and new plays as natural gas prices improve.

"In addition to our core oil and gas exploration and production business segment, we own 77 percent of Penn Virginia GP Holdings, L.P. (NYSE:PVG) and PVG owns the general partner of Penn Virginia Resource Partners, L.P. (NYSE:PVR) and is PVR’s largest limited partner unitholder. As the owner of the general partner and largest unitholder of PVG, we report our financial results on a consolidated basis with the financial results of PVG. At current distribution rates, our ownership of PVG and PVR provides approximately $46 million of annualized pre-tax cash flow to us, which we re-deploy into our oil and gas segment. In the second quarter of 2009, PVR’s coal and natural resource management segment (PVR Coal & Natural Resource Management) reported relatively stable coal royalties revenue and contributions to cash flows, with one percent lower lessee coal production and slightly higher average net coal royalties per ton than the prior year quarter. During the second quarter, PVR’s natural gas midstream segment (PVR Midstream) recorded throughput volumes 31 percent higher than the prior year quarter, while the midstream gross margin, adjusted for the cash impact of hedges, was two percent higher.”

Oil and Gas Segment Review

Second quarter oil and gas production grew 18 percent to 148.9 MMcfe per day, or 13.6 Bcfe, from 125.7 MMcfe per day, or 11.4 Bcfe, in the second quarter of 2008, and was two percent lower than the quarterly record of 152.3 MMcfe per day, or 13.7 Bcfe in the first quarter of 2009. See our separate operational update news release dated July 27, 2009 for a more detailed discussion of second quarter 2009 drilling and production operations for the oil and gas segment.

During the second quarter of 2009, oil and gas segment operating income decreased by $100.4 million as compared to the prior year quarter to an operating loss of $30.7 million. The decrease was due to a $78.6 million, or 58 percent, decrease in revenues and a $21.8 million, or 34 percent, increase in total operating expenses. The decrease in revenues was due to sharp declines in realized commodity prices before considering support from related hedges – a 69 percent decrease in the natural gas price and a 55 percent decrease in the oil price – offset in part by an 18 percent increase in oil and gas production. The increase in operating expenses was primarily due to the production increase, $6.7 million of rig standby charges, $6.3 million of increased amortization of unproved properties included in exploration expense, a $8.3 million increase in depreciation, depletion and amortization (DD&A) expense and $3.3 million of impairments, offset in part by a $3.3 million decrease in taxes other than income as a result of the decrease in commodity prices.

In the second quarter of 2009, total oil and gas segment expenses, excluding the rig standby and impairment charges, increased by $10.2 million, or 16 percent, to $74.9 million, or $5.52 per Mcfe produced, from $64.6 million, or $5.65 per Mcfe produced, in the second quarter of 2008, as discussed below:

• Second quarter 2009 cash operating expenses of $24.2 million, or $1.79 per Mcfe produced, were $2.1 million, or eight percent, lower than the $26.3 million, or $2.30 per Mcfe produced, in the second quarter of 2008. The decrease in unit cash operating expenses was primarily due to lower taxes other than income and lower lease operating expense, as discussed below:
  • Lease operating expense decreased to $1.09 per Mcfe from $1.23 per Mcfe primarily due to decreased overall service costs due to sharply lower commodity prices and reduced water disposal and other costs as compared to the prior year quarter;
  • Taxes other than income decreased to $0.28 per Mcfe from $0.62 per Mcfe primarily due to decreased severance taxes related to sharply lower commodity prices; and
  • Segment general and administrative (G&A) expense decreased to $0.42 per Mcfe as compared to $0.45 per Mcfe primarily due to the production increase.

• Exploration expense, excluding drilling rig standby charges discussed below, increased to $10.7 million in the second quarter of 2009, as compared to $6.7 million in the prior year quarter, primarily due to $6.3 million of increased amortization of unproved properties related to higher leasehold acquisition costs in our East Texas, Mid-Continent and Gulf Coast regions.
• DD&A expense increased by $8.3 million, or 26 percent, to $39.9 million, or $2.94 per Mcfe, in the second quarter of 2009 from $31.6 million, or $2.76 per Mcfe, in the prior year quarter. The overall increase in DD&A expense was primarily due to the production increase, as well as the higher depletion rate per unit of production a result of higher drilling costs and leasehold acquisitions.

In the first quarter of 2009, we opted to defer the drilling of wells in several of our plays due to unfavorable economic conditions. As a result, we amended certain drilling rig contracts to delay commencement of drilling until January 2010. In the second quarter of 2009, we expensed approximately $6.7 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period. We will evaluate economic conditions through the remainder of 2009 to determine whether to continue to defer drilling. This decision could result in additional standby expense of up to approximately $8.0 million during the second half of 2009.

During the second quarter of 2009, we incurred approximately $3.3 million of impairments. These charges were primarily related to the write-down in value of certain field pipe inventories. In addition, during the second quarter we recorded a loss on the sale of assets of $1.6 million related to the sales of inventory and an oil and gas property.

Coal & Natural Resource Management and Natural Gas Midstream Segment Review (PVR and PVG)

As the owner of the general partner and largest unitholder of PVG, we report our financial results on a consolidated basis with the financial results of PVG. A conversion of the GAAP-compliant financial statements ("As reported”) to the equity method of accounting ("As adjusted”) is included in the "Conversion to Non-GAAP Equity Method” table in this release. Using the equity method, PVG’s results are reduced to a few line items and the results from oil and gas operations and corporate are therefore highlighted. We believe that the financial statements presented using the equity method are less complex and more comparable to those of other oil and gas exploration and production companies. Financial and operational results and full-year 2009 guidance for each of PVR’s segments are provided in the financial tables later in this release. In addition, operational updates for these segments are discussed in more detail in PVR’s news release dated August 5, 2009. Please visit PVR’s website, www.pvresource.com, under "For Investors” for a copy of the release.

Operating income for PVR Coal & Natural Resource Management decreased by $3.7 million, or 15 percent, to $20.3 million in the second quarter of 2009. The decrease was primarily due to a six percent decrease in revenues, net of coal royalties expense, primarily due to decreases in oil and gas royalties, timber and other revenues, as well as an increase in G&A expense. Coal royalties revenue, net of coal royalties expense, was relatively flat as compared to the prior year quarter. Operating income for PVR Midstream, adjusted for the cash impact of derivatives, decreased by $7.7 million from $12.1 million in the second quarter of 2008 to $4.4 million in the second quarter of 2009. This decrease was primarily due to lower other revenues and increased operating and G&A expenses, offset in part by a two percent increase in midstream gross margin, adjusted for the cash impact of derivatives. As of June 30, 2009, PVR had outstanding borrowings of $597.1 million under its $800 million revolving credit facility with unused availability of approximately $200 million.

As previously announced, on August 20, 2009, PVG will pay to unitholders of record as of August 3, 2009 a quarterly cash distribution of $0.38 per unit, or an annualized rate of $1.52 per unit, covering the period of April 1 through June 30, 2009. On an annualized basis, this represents a six percent increase over the annualized distribution of $1.44 per unit with respect to the same quarter of 2008 and is unchanged from the distribution paid with respect to each of the previous three quarters. As a result of PVG’s distribution, we will receive a cash distribution of $11.4 million in the third quarter of 2009, which would be $45.7 million on an annualized basis.

Guidance for 2009

See the Guidance Table included in this release for guidance estimates for full-year 2009. These estimates, including capital expenditure plans, which were discussed in our July 27 operational update, are meant to provide guidance only and are subject to revision as our and PVR’s operating environments change.

Second Quarter 2009 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss second quarter 2009 financial and operational results, is scheduled for Thursday, August 6, 2009 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 1-877-407-9205 five to ten minutes before the scheduled start of the conference call, or via webcast by logging on to our website at www.pennvirginia.com at least 20 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay of the call will be available until August 20, 2009 at 11:59 p.m. ET by dialing 1-877-660-6853 and using the following replay pass codes: account #286, conference ID #327743. An on-demand replay of the conference call will be available at our website beginning shortly after the call.

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 the East Texas, Mississippi, the Mid-Continent region, the Appalachian Basin and the Gulf Coast of Louisiana and Texas. We also own approximately 77 percent of PVG, the owner of the general partner and the largest unit holder of PVR, a manager of coal and natural resource properties and related assets and the operator of a midstream natural gas gathering and processing business.

For more information, please visit PVA’s 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, NGLs, crude oil and coal; 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 Revolver; our ability to develop and replace oil and gas reserves and the price for which such reserves can be acquired; any impairment writedowns of our reserves or assets; reductions in our anticipated capital expenditures; the relationship between natural gas, NGL, crude oil and coal prices; the projected demand for and supply of natural gas, NGLs, crude oil and coal; 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 and coal industries generally and among natural gas midstream companies; the extent to which the amount and quality of actual production of our oil and natural gas or PVR’s coal differ from estimated proved oil and gas reserves and recoverable coal reserves; PVR’s ability to generate sufficient cash from its businesses to maintain and pay the quarterly distribution to its general partner and its unitholders; the experience and financial condition of PVR’s coal lessees and natural gas midstream customers, including the lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others; operating risks, including unanticipated geological problems, incidental to our business and to PVR’s coal or natural gas midstream business; PVR’s ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms; PVR’s ability to retain existing or acquire new natural gas midstream customers and coal lessees; the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves and obtain favorable contracts for such production; 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, of PVR’s lessees’ mining operations and related coal infrastructure projects and new processing plants in PVR’s natural gas midstream business; environmental risks affecting the drilling and producing of oil and gas wells, the mining of coal reserves or the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us and by PVR or PVR’s lessees; hedging results; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of current and future litigation regarding mine permitting; 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); PVG’s ability to generate sufficient cash from its interests in PVR to maintain and pay the quarterly distribution to its general partner and its unitholders; uncertainties relating to our continued ownership of interests in PVG and PVR; and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

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, 2008. 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
CONSOLIDATED STATEMENTS OF EARNINGS - unaudited
(in thousands, except per share data)
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008 (a)				2009				2008 (a)
Revenues
Natural gas		$	39,830			$	113,212			$	92,651			$	193,725
Crude oil			11,825				14,463				18,153				23,678
Natural gas liquids (NGLs)			4,336				6,538				7,706				8,406
Natural gas midstream			91,655				184,298				186,861				309,346
Coal royalties			29,997				31,641				60,627				55,603
Other			6,274				10,262				17,079				18,791
Total revenues			183,917				360,414				383,077				609,549
Expenses
Cost of midstream gas purchased			71,933				152,986				151,331				252,683
Operating			22,648				22,214				45,350				43,216
Exploration			10,733				6,739				22,181				11,419
Exploration - drilling rig standby charges (b)			6,739				-				16,603				-
Taxes other than income			4,930				8,259				11,362				15,654
General and administrative (excluding equity compensation)			16,565				16,987				31,659				33,088
Equity-based compensation (c)			3,790				2,071				7,182				3,629
Depreciation, depletion and amortization			58,218				44,934				115,291				83,503
Impairments			3,279				-				4,475				-
Loss on sale of assets			1,599				-				1,599				-
Total expenses			200,434				254,190				407,033				443,192
Operating income (loss)			(16,517	)			106,224				(23,956	)			166,357
Other income (expense)
Interest expense			(15,046	)			(11,345	)			(27,548	)			(22,092	)
Derivatives			752				(103,618	)			11,007				(129,519	)
Other			353				975				1,926				3,306
Income (loss) before income taxes and noncontrolling interests			(30,458	)			(7,764	)			(38,571	)			18,052
Income tax benefit			14,620				7,163				19,182				4,569
Net income (loss)		$	(15,838	)		$	(601	)		$	(19,389	)		$	22,621
Net income attributable to noncontrolling interests			(6,345	)			(3,948	)			(10,003	)			(23,976	)
Net loss attributable to PVA		$	(22,183	)		$	(4,549	)		$	(29,392	)		$	(1,355	)
Net income (loss) per share attributable to PVA common shareholders
Basic		$	(0.52	)		$	(0.11	)		$	(0.69	)		$	(0.03	)
Diluted (d)		$	(0.52	)		$	(0.11	)		$	(0.69	)		$	(0.03	)
Weighted average shares outstanding, basic			42,798				41,740				42,422				41,642
Weighted average shares outstanding, diluted			42,798				41,740				42,422				41,642
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Production
Natural gas (MMcf)			11,422				10,075				23,224				19,823
Crude oil (MBbls)			215				119				386				214
NGLs (MBbls)			140				109				287				143
Total natural gas, crude oil and NGL production (MMcfe)			13,552				11,443				27,262				21,965
Prices
Natural gas ($ per Mcf)		$	3.49			$	11.24			$	3.99			$	9.77
Crude oil ($ per Bbl)		$	55.00			$	121.54			$	47.03			$	110.64
NGLs ($ per Bbl)		$	30.97			$	59.98			$	26.85			$	58.78

(a) As a result of adopting FASB Staff Position No. APB 14-1, Accounting for Convertible Debt Instruments that May be Settled in Cash upon Conversion (Including Partial Cash Settlement), we are required to present our results of operations retrospectively as if the standard had been in effect for all periods presented.

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

(c) 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 SFAS No. 123(R), Share-Based Payment.

(d) Net income per share attributable to PVA common shareholders, diluted includes an adjustment to net income for the dilutive effect of PVR's net income allocated to unvested PVR equity compensation awards that we hold until vesting.

PENN VIRGINIA CORPORATION
CONSOLIDATED BALANCE SHEETS - unaudited
(in thousands)
							June 30,				December 31,
							2009				2008
Assets
Current assets						$	189,540			$	263,518
Net property and equipment							2,531,447				2,512,177
Other assets							235,952				220,870
Total assets						$	2,956,939			$	2,996,565
Liabilities and shareholders' equity
Current liabilities						$	143,034			$	247,594
Long-term debt of PVR							597,100				568,100
Revolving credit facility							70,000				332,000
Senior notes							291,115				-
Convertible notes							203,217				199,896
Other liabilities and deferred taxes							305,610				312,645
PVA shareholders' equity							1,073,269				1,039,103
Noncontrolling interests							273,594				297,227
Total shareholders' equity							1,346,863				1,336,330
Total liabilities and shareholders' equity						$	2,956,939			$	2,996,565
CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)
			Three Months Ended								Six Months Ended
			June 30,								June 30,
			2009				2008				2009				2008
Cash flows from operating activities
Net income (loss)		$	(15,838	)		$	(601	)		$	(19,389	)		$	22,621
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			58,218				44,934				115,291				83,503
Impairments			3,279				-				4,475				-
Derivative contracts:
Total derivative losses (gains)			668				105,135				(9,133	)			132,144
Cash receipts (payments) to settle derivatives			17,281				(18,032	)			36,429				(26,985	)
Deferred income taxes			(14,166	)			(3,589	)			(18,800	)			(1,447	)
Dry hole and unproved leasehold expense			9,379				5,919				19,883				9,472
Other			9,888				2,222				13,379				1,256
Operating cash flow (see attached table "Certain Non-GAAP Financial Measures")			68,709				135,988				142,135				220,564
Changes in operating assets and liabilities			(33,751	)			(17,248	)			(4,158	)			(35,672	)
Net cash provided by operating activities			34,958				118,740				137,977				184,892
Cash flows from investing activities
Acquisitions, net of cash acquired			(3,120	)			(111,367	)			(6,193	)			(116,107	)
Additions to property and equipment			(56,982	)			(120,512	)			(193,195	)			(229,174	)
Other			5,568				334				5,822				739
Net cash used in investing activities			(54,534	)			(231,545	)			(193,566	)			(344,542	)
Cash flows from financing activities
Dividends paid			(2,370	)			(2,342	)			(4,719	)			(4,686	)
Distributions paid to noncontrolling interest holders			(18,455	)			(14,172	)			(36,910	)			(27,912	)
Net proceeds from (repayments of) PVA borrowings			(28,991	)			29,000				29,009				83,000
Net proceeds from (repayments of) PVR borrowings			2,000				(32,600	)			29,000				(30,600	)
Proceeds from equity issuance			64,835				138,015				64,835				138,015
Other			(8,827	)			5,504				(25,627	)			10,786
Net cash provided by financing activities			8,192				123,405				55,588				168,603
Net increase (decrease) in cash and cash equivalents			(11,384	)			10,600				(1	)			8,953
Cash and cash equivalents - beginning of period			29,721				32,880				18,338				34,527
Cash and cash equivalents - end of period		$	18,337			$	43,480			$	18,337			$	43,480

PENN VIRGINIA CORPORATION
QUARTERLY SEGMENT INFORMATION - unaudited
(in thousands except where noted)
Three Months Ended June 30, 2009		Oil and Gas								Coal and Natural Resource Management			Natural Gas Midstream			Other				Consolidated
		Amount				per Mcfe(a)
Production
Total natural gas, crude oil and NGLs (MMcfe)			13,552
Natural gas (MMcf)			11,422
Crude oil (MBbls)			215
NGLs (MBbls)			140
Coal royalty tons (thousands of tons)											8,739
Midstream system throughput volumes (MMcf)														31,342
Revenues
Natural gas		$	39,830			$	3.49			$	-		$	-		$	-			$	39,830
Crude Oil			11,825				55.00				-			-			-				11,825
NGLs			4,336				30.97				-			-			-				4,336
Natural gas midstream			-								-			113,060			(21,405	)			91,655
Coal royalties			-								29,997			-			-				29,997
Other			(212	)							5,147			1,215			124				6,274
Total revenues			55,779				4.12				35,144			114,275			(21,281	)			183,917
Expenses
Cost of midstream gas purchased			-				-				-			92,154			(20,221	)			71,933
Operating expense			14,748				1.09				2,327			6,691			(1,118	)			22,648
Exploration			10,733				0.79				-			-			-				10,733
Exploration - Drilling rig standby charges			6,739				0.50				-			-			-				6,739
Taxes other than income			3,744				0.28				300			680			206				4,930
General and administrative			5,713				0.42				4,020			4,237			6,385				20,355
Depreciation, depletion and amortization			39,917				2.94				8,164			9,453			684				58,218
Impairments			3,279				0.24				-			-			-				3,279
Loss on sale of assets			1,599				0.12				-			-			-				1,599
Total expenses			86,472				6.38				14,811			113,215			(14,064	)			200,434
Operating income (loss)		$	(30,693	)		$	(2.26	)		$	20,333		$	1,060		$	(7,217	)		$	(16,517	)
Additions to property and equipment		$	39,240							$	606		$	15,208		$	1,048			$	56,102
Three Months Ended June 30, 2008		Oil and Gas								Coal and Natural Resource Management			Natural Gas Midstream			Other				Consolidated
		Amount				per Mcfe(a)
Production
Total natural gas, crude oil and NGLs (MMcfe)			11,443
Natural gas (MMcf)			10,075
Crude oil (MBbls)			119
NGLs (MBbls)			109
Coal royalty tons (thousands of tons)											8,839
Midstream system throughput volumes (MMcf)														23,884
Revenues
Natural gas		$	113,212			$	11.24			$	-		$	-		$	-			$	113,212
Crude oil			14,463				121.54				-			-			-				14,463
NGLs			6,538				59.98				-			-			-				6,538
Natural gas midstream			-								-			234,797			(50,499	)			184,298
Coal royalties			-								31,641			-			-				31,641
Other			154								7,415			2,652			41				10,262
Total revenues			134,367				11.74				39,056			237,449			(50,458	)			360,414
Expenses
Cost of midstream gas purchased			-				-				-			202,819			(49,833	)			152,986
Operating expense			14,094				1.23				3,902			4,817			(599	)			22,214
Exploration			6,739				0.59				-			-			-				6,739
Taxes other than income			7,085				0.62				371			605			198				8,259
General and administrative			5,163				0.45				3,274			3,469			7,152				19,058
Depreciation, depletion and amortization			31,568				2.76				7,526			5,393			447				44,934
Total expenses			64,649				5.65				15,073			217,103			(42,635	)			254,190
Operating income (loss)		$	69,718			$	6.09			$	23,983		$	20,346		$	(7,823	)		$	106,224
Additions to property and equipment		$	114,213							$	24,641		$	92,769		$	256			$	231,879

(a) Natural gas revenues are shown per Mcf, crude oil and NGL revenues are shown per Bbl, and all other amounts are shown per Mcfe.

PENN VIRGINIA CORPORATION
YEAR-TO-DATE SEGMENT INFORMATION - unaudited
(in thousands except where noted)
Six Months Ended June 30, 2009		Oil and Gas								Coal and Natural Resource Management			Natural Gas Midstream				Other				Consolidated
		Amount				per Mcfe(a)
Production
Total natural gas, crude oil and NGLs (MMcfe)			27,262
Natural gas (MMcf)			23,224
Crude oil (MBbls)			386
NGLs (MBbls)			287
Coal royalty tons (thousands of tons)											17,487
Midstream system throughput volumes (MMcf)														63,622
Revenues
Natural gas		$	92,651			$	3.99			$	-		$	-			$	-			$	92,651
Crude Oil			18,153				47.03				-			-				-				18,153
NGLs			7,706				26.85				-			-				-				7,706
Natural gas midstream			-								-			230,439				(43,578	)			186,861
Coal royalties			-								60,627			-				-				60,627
Other			1,834								12,769			2,343				133				17,079
Total revenues			120,344				4.41				73,396			232,782				(43,445	)			383,077
Expenses
Cost of midstream gas purchased			-				-				-			192,774				(41,443	)			151,331
Operating expense			29,511				1.08				4,434			13,474				(2,069	)			45,350
Exploration			22,181				0.81				-			-				-				22,181
Exploration - Drilling rig standby charges			16,603				0.61				-			-				-				16,603
Taxes other than income			8,570				0.31				725			1,478				589				11,362
General and administrative			10,837				0.40				7,372			8,481				12,151				38,841
Depreciation, depletion and amortization			79,916				2.94				15,558			18,562				1,255				115,291
Impairments			4,475				0.16				-			-				-				4,475
Loss on sale of assets			1,599				0.06				-			-				-				1,599
Total expenses			173,692				6.37				28,089			234,769				(29,517	)			407,033
Operating income (loss)		$	(53,348	)		$	(1.96	)		$	45,307		$	(1,987	)		$	(13,928	)		$	(23,956	)
Additions to property and equipment		$	159,814							$	1,906		$	32,214			$	1,454			$	195,388
Six Months Ended June 30, 2008		Oil and Gas								Coal and Natural Resource Management			Natural Gas Midstream				Other				Consolidated
		Amount				per Mcfe(a)
Production
Total natural gas, crude oil and NGLs (MMcfe)			21,965
Natural gas (MMcf)			19,823
Crude oil (MBbls)			214
NGLs (MBbls)			143
Coal royalty tons (thousands of tons)											16,479
Midstream system throughput volumes (MMcf)														41,171
Revenues
Natural gas		$	193,725			$	9.77			$	-		$	-			$	-			$	193,725
Crude oil			23,678				110.64				-			-				-				23,678
NGLs			8,406				58.78				-			-				-				8,406
Natural gas midstream			-								-			359,845				(50,499	)			309,346
Coal royalties			-								55,603			-				-				55,603
Other			857								13,747			4,124				63				18,791
Total revenues			226,666				10.32				69,350			363,969				(50,436	)			609,549
Expenses
Cost of midstream gas purchased			-				-				-			302,516				(49,833	)			252,683
Operating expense			28,303				1.29				6,645			8,867				(599	)			43,216
Exploration			11,419				0.52				-			-				-				11,419
Taxes other than income			12,943				0.59				742			1,306				663				15,654
General and administrative			9,747				0.44				6,459			6,802				13,709				36,717
Depreciation, depletion and amortization			58,184				2.65				13,939			10,480				900				83,503
Total expenses			120,596				5.49				27,785			329,971				(35,160	)			443,192
Operating income (loss)		$	106,070			$	4.83			$	41,565		$	33,998			$	(15,276	)		$	166,357
Additions to property and equipment		$	209,402							$	24,689		$	110,391			$	799			$	345,281

(a) Natural gas revenues are shown per Mcf, crude oil and NGL revenues are shown per Bbl, and all other amounts are shown per Mcfe.

PENN VIRGINIA CORPORATION
CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited
(in thousands)
		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Reconciliation of GAAP "Net cash provided by operating activities" to Non-GAAP "Operating cash flow"
Net cash provided by operating activities		$	34,958			$	118,740			$	137,977			$	184,892
Adjustments:
Changes in operating assets and liabilities			33,751				17,248				4,158				35,672
Operating cash flow (a)		$	68,709			$	135,988			$	142,135			$	220,564
Reconciliation of GAAP "Net income (loss) attributable to PVA" to Non-GAAP "Net income (loss) attributable to PVA as adjusted"
Net loss attributable to PVA		$	(22,183	)		$	(4,549	)		$	(29,392	)		$	(1,355	)
Adjustments for derivatives:
Derivative losses included in income			668				105,135				(9,133	)			132,144
Cash settlements of derivatives			17,281				(18,032	)			36,429				(26,985	)
Adjustment for drilling rig standby charges			6,739				-				16,603				-
Adjustment for impairments			3,279				-				4,475				-
Adjustment for loss on sale of assets			1,599				-				1,599				-
Impact of adjustments on noncontrolling interest			(2,640	)			-				(6,915	)			-
Impact of adjustments on income tax expense			(10,753	)			(33,796	)			(17,004	)			(40,802	)
		$	(6,010	)		$	48,758			$	(3,338	)		$	63,002
Less: Portion of subsidiary net income allocated to undistributed share-based compensation awards, net of taxes			(11	)			(58	)			(24	)			(161	)
Net income (loss) attributable to PVA as adjusted (b)		$	(6,021	)		$	48,700			$	(3,362	)		$	62,841
Net income (loss) attributable to PVA as adjusted per share, diluted		$	(0.14	)		$	1.17			$	(0.08	)		$	1.51

(a) Operating cash flow represents net cash provided by operating activities before changes in operating assets and liabilities. We believe that operating cash flow is widely accepted as a financial indicator of an energy company's ability to generate cash which is used to internally fund investing activities, service debt and pay dividends. Operating cash flow is widely used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the energy industry. Operating cash flow is presented because we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.

(b) Net income attributable to PVA as adjusted represents net income attributable to PVA adjusted to exclude the effects of non-cash changes in the fair value of derivatives, the effects of drilling rig stand-by charges, the effects of impairments, the effects of loss on the sale of assets and the effects of PVR's net income allocated to unvested PVR equity compensation awards that we hold 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, as well as companies within the natural gas midstream industry. We use this information for comparative purposes within these industries. Net income 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
CONVERSION TO NON-GAAP EQUITY METHOD - unaudited
(in thousands)
Reconciliation of GAAP "Income Statements As Reported" to Non-GAAP "Income Statements As Adjusted" (a):
		Three Months Ended June 30, 2009												Three Months Ended June 30, 2008
		As Reported				Adjustments				As Adjusted				As Reported				Adjustments				As Adjusted
Revenues
Natural gas		$	39,830			$	-			$	39,830			$	113,212			$	-			$	113,212
Crude oil			11,825				-				11,825				14,463				-				14,463
NGLs			4,336				-				4,336				6,538				-				6,538
Natural gas midstream			91,655				(91,655	)			-				184,298				(184,298	)			-
Coal royalties			29,997				(29,997	)			-				31,641				(31,641	)			-
Other			6,274				(6,362	)			(88	)			10,262				(10,067	)			195
Total revenues			183,917				(128,014	)			55,903				360,414				(226,006	)			134,408
Expenses
Cost of midstream gas purchased			71,933				(71,933	)			-				152,986				(152,986	)			-
Operating			22,648				(9,018	)			13,630				22,214				(8,719	)			13,495
Exploration			10,733				-				10,733				6,739				-				6,739
Exploration - drilling rig standby charges			6,739				-				6,739				-				-				-
Taxes other than income			4,930				(980	)			3,950				8,259				(976	)			7,283
General and administrative			20,355				(8,819	)			11,536				19,058				(7,305	)			11,753
Depreciation, depletion and amortization			58,218				(17,617	)			40,601				44,934				(12,919	)			32,015
Impairments			3,279				-				3,279				-				-				-
Loss on sale of assets			1,599				-				1,599				-				-				-
Total expenses			200,434				(108,367	)			92,067				254,190				(182,905	)			71,285
Operating income (loss)			(16,517	)			(19,647	)			(36,164	)			106,224				(43,101	)			63,123
Other income (expense)
Interest expense			(15,046	)			6,365				(8,681	)			(11,345	)			5,374				(5,971	)
Derivatives			752				2,034				2,786				(103,618	)			29,942				(73,676	)
Equity earnings in PVG and PVR			-				5,250				5,250				-				4,513				4,513
Other			353				(347	)			6				975				(676	)			299
Income (loss) before taxes and noncontrolling interests			(30,458	)			(6,345	)			(36,803	)			(7,764	)			(3,948	)			(11,712	)
Income tax benefit (expense)			14,620				-				14,620				7,163				-				7,163
Net income (loss)			(15,838	)			(6,345	)			(22,183	)			(601	)			(3,948	)			(4,549	)
Net income attributable to noncontrolling interests			(6,345	)			6,345				-				(3,948	)			3,948				-
Net income (loss) attributable to PVA		$	(22,183	)		$	-			$	(22,183	)		$	(4,549	)		$	-			$	(4,549	)
		Six Months Ended June 30, 2009												Six Months Ended June 30, 2008
		As Reported				Adjustments				As Adjusted				As Reported				Adjustments				As Adjusted
Revenues
Natural gas		$	92,651			$	-			$	92,651			$	193,725			$	-			$	193,725
Crude oil			18,153				-				18,153				23,678				-				23,678
NGLs			7,706				-				7,706				8,406				-				8,406
Natural gas midstream			186,861				(186,861	)			-				309,346				(309,346	)			-
Coal royalties			60,627				(60,627	)			-				55,603				(55,603	)			-
Other			17,079				(15,112	)			1,967				18,791				(14,168	)			4,623
Total revenues			383,077				(262,600	)			120,477				609,549				(379,117	)			230,432
Expenses
Cost of midstream gas purchased			151,331				(151,331	)			-				252,683				(252,683	)			-
Operating			45,350				(17,908	)			27,442				43,216				(15,512	)			27,704
Exploration			22,181				-				22,181				11,419				-				11,419
Exploration - drilling rig standby charges			16,603				-				16,603				-				-				-
Taxes other than income			11,362				(2,203	)			9,159				15,654				(2,048	)			13,606
General and administrative			38,841				(16,952	)			21,889				36,717				(14,439	)			22,278
Depreciation, depletion and amortization			115,291				(34,120	)			81,171				83,503				(24,419	)			59,084
Impairments			4,475				-				4,475				-				-				-
Loss on sale of assets			1,599				-				1,599				-				-				-
Total expenses			407,033				(222,514	)			184,519				443,192				(309,101	)			134,091
Operating income (loss)			(23,956	)			(40,086	)			(64,042	)			166,357				(70,016	)			96,341
Other income (expense)
Interest expense			(27,548	)			11,981				(15,567	)			(22,092	)			10,306				(11,786	)
Derivatives			11,007				9,195				20,202				(129,519	)			22,166				(107,353	)
Equity earnings in PVG and PVR			-				9,583				9,583				-				14,614				14,614
Other			1,926				(676	)			1,250				3,306				(1,046	)			2,260
Income (loss) before taxes and noncontrolling interests			(38,571	)			(10,003	)			(48,574	)			18,052				(23,976	)			(5,924	)
Income tax benefit (expense)			19,182				-				19,182				4,569				-				4,569
Net income (loss)			(19,389	)			(10,003	)			(29,392	)			22,621				(23,976	)			(1,355	)
Net income attributable to noncontrolling interests			(10,003	)			10,003				-				(23,976	)			23,976				-
Net income (loss) attributable to PVA		$	(29,392	)		$	-			$	(29,392	)		$	(1,355	)		$	-			$	(1,355	)

(a) Equity method income statements represent consolidated income statements, minus 100% of PVG’s consolidated results of operations, plus noncontrolling interests which represents the portion of PVG’s consolidated results of operations that we do not own. We believe equity method income statements provide useful information to allow the public to more easily discern PVG’s effect on our operations.

PENN VIRGINIA CORPORATION
CONVERSION TO NON-GAAP EQUITY METHOD - unaudited (continued)
(in thousands)
Reconciliation of GAAP "Balance Sheet As Reported" to Non-GAAP "Balance Sheet As Adjusted" (a):
		June 30, 2009												December 31, 2008
		As Reported				Adjustments				As Adjusted				As Reported				Adjustments				As Adjusted
Assets
Current assets		$	189,540			$	(95,817	)		$	93,723			$	263,518			$	(126,299	)		$	137,219
Net property and equipment			2,531,447				(892,944	)			1,638,503				2,512,177				(895,119	)			1,617,058
Equity investment in PVG and PVR			-				227,911				227,911				-				248,211				248,211
Other assets			235,952				(211,126	)			24,826				220,870				(206,256	)			14,614
Total assets		$	2,956,939			$	(971,976	)		$	1,984,963			$	2,996,565			$	(979,463	)		$	2,017,102
Liabilities and shareholders' equity
Current liabilities		$	143,034			$	(74,187	)		$	68,847			$	247,594			$	(89,908	)		$	157,686
Long-term debt			1,161,432				(597,100	)			564,332				1,099,996				(568,100	)			531,896
Other liabilities and deferred taxes			305,610				(27,095	)			278,515				312,645				(24,228	)			288,417
PVA shareholders' equity			1,073,269				-				1,073,269				1,039,103				-				1,039,103
Noncontrolling interest			273,594				(273,594	)			-				297,227				(297,227	)			-
Total shareholders' equity			1,346,863				(273,594	)			1,073,269				1,336,330				(297,227	)			1,039,103
Total liabilities and shareholders' equity		$	2,956,939			$	(971,976	)		$	1,984,963			$	2,996,565			$	(979,463	)		$	2,017,102
Reconciliation of GAAP "Statement of Cash Flows As Reported" to Non-GAAP "Statement of Cash Flows As Adjusted" (b):
		Three Months Ended June 30, 2009												Three Months Ended June 30, 2008
		As Reported				Adjustments				As Adjusted				As Reported				Adjustments				As Adjusted
Cash flows from operating activities
Net loss		$	(15,838	)		$	-			$	(15,838	)		$	(601	)		$	-			$	(601	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization			58,218				(17,617	)			40,601				44,934				(12,919	)			32,015
Impairments			3,279				-				3,279				-				-				-
Derivative contracts:
Total derivative losses (gains)			668				(2,951	)			(2,283	)			105,135				(31,459	)			73,676
Cash receipts (payments) to settle derivatives			17,281				(1,613	)			15,668				(18,032	)			9,703				(8,329	)
Deferred income taxes			(14,166	)			-				(14,166	)			(3,589	)			-				(3,589	)
Dry hole and unproved leasehold expense			9,379				-				9,379				5,919				-				5,919
Investment in PVG and PVR			-				(12,780	)			(12,780	)			-				(8,952	)			(8,952	)
Cash distributions from PVG and PVG			-				11,532				11,532				-				11,048				11,048
Other			9,888				(1,306	)			8,582				2,222				(335	)			1,887
Operating cash flow			68,709				(24,735	)			43,974				135,988				(32,914	)			103,074
Changes in operating assets and liabilities			(33,751	)			(2,610	)			(36,361	)			(17,248	)			(500	)			(17,748	)
Net cash provided by (used in) operating activities			34,958				(27,345	)			7,613				118,740				(33,414	)			85,326
Net cash provided by (used in) investing activities			(54,534	)			15,507				(39,027	)			(231,545	)			117,076				(114,469	)
Net cash provided by (used in) financing activities			8,192				16,455				24,647				123,405				(90,623	)			32,782
Net increase (decrease) in cash and cash equivalents			(11,384	)			4,617				(6,767	)			10,600				(6,961	)			3,639
Cash and cash equivalents-beginning balance			29,721				(21,710	)			8,011				32,880				(18,981	)			13,899
Cash and cash equivalents-ending balance		$	18,337			$	(17,093	)		$	1,244			$	43,480			$	(25,942	)		$	17,538
		Six Months Ended June 30, 2009												Six Months Ended June 30, 2008
		As Reported				Adjustments				As Adjusted				As Reported				Adjustments				As Adjusted
Cash flows from operating activities
Net income (loss)		$	(19,389	)		$	-			$	(19,389	)		$	22,621			$	-			$	22,621
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization			115,291				(34,120	)			81,171				83,503				(24,419	)			59,084
Impairments			4,475				-				4,475				-				-				-
Derivative contracts:
Total derivative losses (gains)			(9,133	)			(10,566	)			(19,699	)			132,144				(24,791	)			107,353
Cash settlements of derivatives			36,429				(4,449	)			31,980				(26,985	)			19,225				(7,760	)
Deferred income taxes			(18,800	)			-				(18,800	)			(1,447	)			-				(1,447	)
Dry hole and unproved leasehold expense			19,883				-				19,883				9,472				-				9,472
Investment in PVG and PVR			-				(21,721	)			(21,721	)			-				(42,959	)			(42,959	)
Cash distributions from PVG and PVG			-				23,064				23,064				-				21,480				21,480
Other			13,379				(31	)			13,348				1,256				79				1,335
Operating cash flow			142,135				(47,823	)			94,312				220,564				(51,385	)			169,179
Changes in operating assets and liabilities			(4,158	)			(1,648	)			(5,806	)			(35,672	)			424				(35,248	)
Net cash provided by (used in) operating activities			137,977				(49,471	)			88,506				184,892				(50,961	)			133,931
Net cash provided by (used in) investing activities			(193,566	)			33,548				(160,018	)			(344,542	)			134,405				(210,137	)
Net cash provided by (used in) financing activities			55,588				17,168				72,756				168,603				(78,883	)			89,720
Net increase (decrease) in cash and cash equivalents			(1	)			1,245				1,244				8,953				4,561				13,514
Cash and cash equivalents-beginning balance			18,338				(18,338	)			-				34,527				(30,503	)			4,024
Cash and cash equivalents-ending balance		$	18,337			$	(17,093	)		$	1,244			$	43,480			$	(25,942	)		$	17,538

(a) Equity method balance sheets represent consolidated balance sheets, minus 100% of PVG’s consolidated balance sheets, excluding noncontrolling interest which represents the portion of PVG’s consolidated balance sheet that we do not own and including other adjustments to eliminate inter-company transactions. We believe equity method balance sheets provide useful information to allow the public to more easily discern PVG’s effect on our assets, liabilities and shareholders’ equity.

(b) Equity method statements of cash flows represent consolidated statements of cash flows, minus 100% of PVG’s consolidated statements of cash flows, excluding noncontrolling interest which represents the portion of PVG’s consolidated results of operations that we do not own and including other adjustments to eliminate inter-company transactions. We believe equity method statements of cash flows provide useful information to allow the public to more easily discern PVG’s effect on our cash flows.

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 2009.
		Actual
		First Quarter				Second Quarter			YTD			Full-Year
Oil & Gas Segment:		2009				2009			2009			2009 Guidance
Production:
Natural gas (Bcf) (a)			11.8			11.4			23.2			41.2		-		42.7
Crude oil (MBbls)			171			215			386			625		-		675
NGLs (MBbls)			147			140			287			515		-		540
Equivalent production (Bcfe)			13.7			13.6			27.3			48.0		-		50.0
Equivalent daily production (MMcfe per day)			152.3			149.5			150.8			131.5		-		137.0
Expenses:
Cash operating expenses ($ per Mcfe)		$	1.80			1.79			1.80			1.85		-		1.95
Exploration		$	21.3			17.5			38.8			60.0		-		70.0
Depreciation, depletion and amortization ($ per Mcfe)		$	2.92			2.94			2.94			2.90		-		3.05
Impairments		$	1.2			3.3			4.5			4.5		-		4.5
Loss on sale of assets		$	-			1.6			1.6			1.6		-		1.6
Capital expenditures:
Development drilling		$	76.5			37.3			113.8			135.0		-		145.0
Exploratory drilling		$	1.5			-			1.5			2.0		-		4.0
Pipeline, gathering, facilities		$	5.1			2.4			7.5			8.0		-		9.0
Seismic		$	0.7			0.4			1.1			1.0		-		2.0
Lease acquisition, field projects and other		$	1.8			2.8			4.6			19.0		-		20.0
Total segment capital expenditures		$	85.6			42.9			128.5			165.0		-		180.0
Coal and Natural Resource Segment (PVR):
Coal royalty tons (millions)			8.7			8.7			17.5			33.0		-		34.0
Revenues:
Average coal royalties per ton		$	3.50			3.43			3.47			3.30		-		3.40
Average coal royalties per ton, net of coal royalties expense		$	3.36			3.25			3.31			3.20		-		3.30
Other		$	7.6			5.1			12.8			23.5		-		24.5
Expenses:
Cash operating expenses		$	5.9			6.6			12.5			22.0		-		23.0
Depreciation, depletion and amortization		$	7.4			8.2			15.6			31.0		-		32.0
Capital expenditures:
Expansion and acquisitions		$	1.3			0.6			1.9			5.0		-		5.5
Maintenance capital expenditures		$	-			-			-			1.0		-		2.0
Total segment capital expenditures		$	1.3			0.6			1.9			6.0		-		7.5
Natural Gas Midstream Segment (PVR):
System throughput volumes (MMcf per day) (b)			359			344			352			350		-		360
Expenses:
Cash operating expenses		$	11.8			11.6			23.4			51.0		-		52.5
Depreciation, depletion and amortization		$	9.1			9.5			18.6			38.0		-		39.0
Capital expenditures:
Expansion and acquisitions		$	11.2			10.3			21.5			70.0		-		72.0
Maintenance capital expenditures		$	3.3			1.4			4.7			11.5		-		13.0
Total segment capital expenditures		$	14.5			11.7			26.2			81.5		-		85.0
Corporate and Other:
General and administrative expense - PVA		$	5.2			5.8			11.0			18.5		-		20.0
General and administrative expense - PVG		$	0.5			0.6			1.1			2.0		-		2.5
Interest expense:
PVA end of period debt outstanding		$	591.5			564.3			564.3
PVA average interest rate			4.3	%		6.0	%		5.2	%
PVR end of period debt outstanding		$	595.1			597.1			597.1
PVR average interest rate			3.9	%		4.2	%		4.0	%
Income tax rate			38.8	%		39.7	%		39.5	%
Cash distributions received from PVG and PVR		$	11.5			11.6			23.1
Other capital expenditures		$	0.6			0.9			1.5			1.0		-		2.0

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

See Notes on subsequent pages.

PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
(dollars in millions except where noted)
Notes to Guidance Table:
(a)		The following table shows our current derivative positions for natural gas production in the oil and gas segment as of June 30, 2009:
							Weighted Average Price
					Average Volume Per Day		Additional Put Option			Floor			Ceiling
		Natural gas costless collars			(MMBtu)					(per MMBtu)
		Third quarter 2009			15,000					$	4.25		$	5.70
		Fourth quarter 2009			15,000					$	4.25		$	5.70
		First quarter 2010			35,000					$	4.96		$	7.41
		Second quarter 2010			30,000					$	5.33		$	8.02
		Third quarter 2010			30,000					$	5.33		$	8.02
		Fourth quarter 2010			50,000					$	5.65		$	8.77
		First quarter 2011			50,000					$	5.65		$	8.77
		Second quarter 2011			10,000					$	6.00		$	8.00
		Third quarter 2011			10,000					$	6.00		$	8.00
		Natural gas three-way collars (1)			(MMBtu)					(per MMBtu)
		Third quarter 2009			40,000		$	6.38		$	8.75		$	10.79
		Fourth quarter 2009			30,000		$	6.83		$	9.50		$	13.60
		First quarter 2010			30,000		$	6.83		$	9.50		$	13.60
		Natural gas swaps			(MMBtu)					(per MMBtu)
		Third quarter 2009			40,000					$	4.91
		Fourth quarter 2009			40,000					$	4.91
		First quarter 2010			15,000					$	6.19
		Second quarter 2010			30,000					$	6.17
		Third quarter 2010			30,000					$	6.17
		Crude oil costless collars			(barrels)					(per barrel)
		First quarter 2010			500					$	60.00		$	74.75
		Second quarter 2010			500					$	60.00		$	74.75
		Third quarter 2010			500					$	60.00		$	74.75
		Fourth quarter 2010			500					$	60.00		$	74.75
		Crude oil three-way collars (1)			(barrels)					(per barrel)
		First quarter 2009			500		$	80.00		$	110.00		$	179.00
		Second quarter 2009			500		$	80.00		$	110.00		$	179.00
		Third quarter 2009			500		$	80.00		$	110.00		$	179.00
		Fourth quarter 2009			500		$	80.00		$	110.00		$	179.00
		Crude oil swaps			(barrels)					(per barrel)
		Third quarter 2009			500					$	59.25
		Fourth quarter 2009			500					$	59.25

			We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by approximately $17.4 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, oil and gas segment operating income for the remainder of 2009 would increase or decrease by approximately $1.8 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.
			(1) A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

PENN VIRGINIA CORPORATION
GUIDANCE TABLE - unaudited - (continued)
(dollars in millions except where noted)
(b)		The costless collar natural gas prices per MMBtu per quarter include the effects of basis differentials, if any. The following table shows current derivative positions for natural gas production in PVR’s natural gas midstream segment as of June 30, 2009:
						Weighted Average Price
						Collars
				Average Volume Per Day		Additional Put Option			Put			Call
		Crude oil three-way collar		(barrels)					(per barrel)
		Third quarter 2009 through fourth quarter 2009		1,000		$	70.00		$	90.00		$	119.25
		Frac spread collar (1)		(MMBtu)					(per MMBtu)
		Second quarter 2009 through fourth quarter 2009		6,000					$	9.09		$	13.94
		Crude oil collar		(barrels)					(per barrel)
		Third quarter 2010 through fourth quarter 2010		750					$	70.00		$	81.25

			We estimate that, excluding the derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, natural gas midstream gross margin and operating income for the remainder of 2009 would decrease or increase by approximately $2.5 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by approximately $2.4 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.
			(1) PVR’s frac spread is the spread between the purchase price for the natural gas PVR purchases from producers and the sale price for the NGLs that PVR sells after processing. PVR hedges against the variability in its frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMBtu basis.