Penn Virginia Corporation

Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, PA 19087

FOR IMMEDIATE RELEASE

Contact: James W. Dean

Vice President, Investor Relations

Ph: (610) 687-7531 Fax: (610) 687-3688

E-Mail: invest@pennvirginia.com

PENN VIRGINIA CORPORATION

ANNOUNCES THIRD QUARTER 2009 RESULTS

RADNOR, PA (BusinessWire) November 4, 2009 – Penn Virginia Corporation (NYSE: PVA) today reported financial and operational results for the three months ended September 30, 2009 and provided an update of full-year 2009 guidance.

Third Quarter 2009 Highlights

Third quarter 2009 results, with comparisons to third quarter 2008 results, included the following:

· Quarterly oil and gas production of 134.9 million cubic feet of natural gas equivalent (MMcfe) per day, or 12.4 billion cubic feet of natural gas equivalent (Bcfe), a six percent increase as compared to oil and gas production of 127.1 MMcfe per day, or 11.7 Bcfe;

· Increased 2009 guidance for production to a range of 49.0 to 51.0 Bcfe, or six to nine percent higher than 2008, as a result of better than expected third quarter volumes;

· Operating cash flow, a non-GAAP (generally accepted accounting principles) measure, of $64.0 million as compared to operating cash flow of $97.5 million;

· Adjusted net loss, a non-GAAP measure which excludes the effects of the non-cash change in derivatives fair value, drilling rig standby charges, impairments and gains or losses that affect comparability to the prior year period, of $11.2 million, or $0.25 per diluted share, as compared to adjusted net income of $14.0 million, or $0.33 per diluted share;

· Net loss attributable to PVA of $79.9 million, or $1.76 per diluted share, as compared to net income of $123.0 million, or $2.88 per diluted share.  The third quarter of 2009 included an $87.9 million non-cash impairment charge on non-core properties held for sale, while the third quarter of 2008 included $154.9 million of a non-cash change in derivatives fair value and gains on the sale of assets; and

· Subsequent to the end of the third quarter, we completed the syndication of a new 3-year senior secured revolving credit facility with an initial undrawn commitment of $300 million supported by a $420 million approved borrowing base, a 14 percent increase over the current $367 million borrowing base.

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 and a decision to sell non-core properties in the Gulf Coast region impacted our financial results, we are pleased with our third quarter 2009 operational results.  As detailed in our separate operational update, third quarter production was better than anticipated and, accordingly, we have increased full year 2009 production guidance.  In addition, due to the improved outlook for natural gas, recent positive results in our core plays and our improved financial liquidity, we have resumed operated drilling in the Lower Bossier (Haynesville) Shale and Granite Wash plays.

“During the third quarter of 2009, we raised approximately $118 million from the sale of PVG units.  As a result, we have substantially improved our financial liquidity, with $300 million of unused availability on our revolving credit facility and over $90 million of cash on hand.  Furthermore, we expect to complete the sale of non-core properties, primarily along the Texas and Louisiana Gulf Coast, during the fourth quarter of 2009 which will further augment our cash liquidity.  The net effect of both transactions is very positive to our cash and liquidity situation and better positions our company for future growth as a more focused, resource play-driven exploration and production company.

“Our commodity price hedges provided cash flow protection, increasing third quarter effective price realizations from $3.45 per Mcf to $4.90 per Mcf for natural gas.  For the fourth quarter of 2009, we have hedged approximately 82 percent of our estimated natural gas production at average respective floor and ceiling prices of $6.41 and $8.11 per million British thermal units (MMBtu), and 57 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, assuming flat production from the fourth quarter of 2009.  In addition to the cash flow support our hedges have provided, our unit cash costs have continued to improve, including a 15 percent reduction from the prior year quarter and in line with the second quarter of 2009 in spite of the sequential production decline.

“In addition to our core oil and gas exploration and production business segment, we own 51 percent of Penn Virginia GP Holdings, L.P. (NYSE: PVG), which was reduced from 77 percent by our sale of PVG units during the third quarter.  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, which have not changed since the third quarter of 2008, our ownership of PVG and PVR provides approximately $30 million of annualized pre-tax cash flow to us, which we re-deploy into our oil and gas segment.”

Oil and Gas Segment Review

Third quarter oil and gas production grew six percent to 134.9 MMcfe per day, or 12.4 Bcfe, from 127.1 MMcfe per day, or 11.7 Bcfe, in the third quarter of 2008, and was nine percent lower than 148.9 MMcfe per day, or 13.6 Bcfe in the second quarter of 2009.  See our separate operational update news release dated October 30, 2009 for a more detailed discussion of operations for the oil and gas segment.

During the third quarter of 2009, oil and gas segment operating income decreased by $203.6 million as compared to the prior year quarter to an operating loss of $114.6 million.  The decrease was due to a $92.4 million increase in impairments, a $101.0 million, or 64 percent, decrease in revenues, a $7.8 million, or 93 percent, increase in exploration expense and a $2.5 million, or four percent, increase in other operating expenses.  The decrease in revenues was due to sharp declines in realized commodity prices before considering support from related hedges – a 66 percent decrease in the natural gas price, a 44 percent decrease in the oil price and a 55 percent decrease in the price of natural gas liquids (NGLs) – offset in part by the six percent increase in oil and gas production.

The $102.7 million increase in operating expenses was due to an $87.9 million non-cash impairment charge on assets held for sale pertaining to the Gulf Coast region, a $6.7 million increase in depreciation, depletion and amortization (DD&A) expense, a $4.5 million impairment charge primarily related to Bakken properties in North Dakota and $3.7 million of rig standby charges.  These increases in operating expenses were partially offset by a $2.4 million decrease in production taxes due to lower commodity prices and a $1.8 decrease in lease operating expenses despite the production increase. The impairment charge on the Gulf Coast properties relates to a reduction in the carrying value of the assets to a level which is in line with the expected proceeds from their sale, expected during the fourth quarter.

In the third quarter of 2009, total oil and gas segment expenses, excluding the impairment and rig standby charges, increased by $6.6 million, or 11 percent, to $74.3 million, or $5.99 per Mcfe produced, from $67.7 million, or $5.79 per Mcfe produced, in the third quarter of 2008, as discussed below:

· Third quarter 2009 cash operating expenses of $22.6 million, or $1.82 per Mcfe produced, were $4.1 million, or 15 percent, lower than the $26.7 million, or $2.29 per Mcfe produced, in the third 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 17 percent to $1.07 per Mcfe from $1.29 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 39 percent to $0.34 per Mcfe from $0.56 per Mcfe primarily due to decreased severance taxes related to sharply lower commodity prices; and

- Segment general and administrative (G&A) expense decreased seven percent to $0.41 per Mcfe as compared to $0.44 per Mcfe primarily due to the production increase.

· Exploration expense, excluding drilling rig standby charges discussed below, increased 49 percent to $12.4 million in the third quarter of 2009, as compared to $8.3 million in the prior year quarter, primarily due to 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 $6.7 million, or 20 percent, to $39.3 million, or $3.17 per Mcfe, in the third quarter of 2009 from $32.7 million, or $2.79 per Mcfe, in the prior year quarter.  The overall increase in DD&A expense was primarily due to the production increase and a higher depletion rate per unit of production.  The higher depletion rate was primarily due to (i) higher drilling costs on our new horizontal plays and (ii) commodity price and performance-related downward reserve revisions in the non-core Gulf Coast fields, expected to be sold during the fourth quarter of 2009, and on early-stage wells in the Lower Bossier (Haynesville) Shale play.

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 third quarter of 2009, we expensed approximately $3.7 million for lump sum delay fees, minimum daily standby fees and demobilization fees expected to be paid during the standby period.  Continued deferral of the rigs could result in additional standby expense of $0.5 to $1.5 million during the fourth quarter of 2009.

During the third quarter of 2009, we incurred approximately $92.4 million of impairments.  These charges were primarily related to the $87.9 million write-down in value of proved properties in our Gulf Coast region to a carrying value that is in line with the expected proceeds from the anticipated sale of these assets, expected during the fourth quarter of 2009.

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 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 November 4, 2009.  Please visit PVR’s website, www.pvresource.com, under “For Investors” for a copy of the release.

During the third quarter of 2009, we sold 10.0 million units of PVG to the public for net proceeds of $118.1 million.  The net proceeds were used to repay the entire outstanding balance on our revolving credit facility and the remainder of approximately $68 million was held as cash.  As a result, our position in PVG was reduced from 30.1 million units, or 77 percent, to 20.1 million units, or 51 percent.

As previously announced, on November 18, 2009, PVG will pay to unitholders of record as of November 6, 2009 a quarterly cash distribution of $0.38 per unit, or an annualized rate of $1.52 per unit, covering the period of July 1 through September 30, 2009.  The distribution remains unchanged from the distribution paid with respect to each of the previous four quarters.  As a result of PVG’s distribution, we will receive a cash distribution of $7.6 million in the fourth quarter of 2009, or $30.5 million on an annualized basis.

Capital Resources, Credit Facility and Impact of Derivatives

We have completed the syndication of a new 3-year senior secured revolving credit facility with an initial undrawn commitment of $300 million supported by a $420 million approved borrowing base, a 14 percent increase over the current $367 million borrowing base.  The new facility is provided by a syndicate of 12 banks, led by J.P. Morgan Securities Inc., with no individual bank holding more than ten percent of the total commitment.  Pricing for the new credit facility will be unchanged from the existing facility.  The credit facility will close subject to final document review by the bank group.

As of September 30, 2009, we had outstanding borrowings of $530.0 million ($496.4 million carrying value), consisting of $300 million ($291.4 million carrying value) of senior unsecured notes due 2016 and $230.0 million ($204.9 million carrying value) of convertible senior subordinated notes due 2012 and no borrowings against our revolving credit facility.  The $32.0 million decrease in outstanding borrowings as compared to the $562.0 million at December 31, 2008 was primarily due to the repayment of revolver debt following a $64.9 million offering of PVA common shares in May 2009 and a $118.1 million offering of PVG common units in September 2009, as well as free cash flow during the third quarter of 2009, net of spending to fund our oil and gas capital expenditures during the first nine months of 2009.  As of September 30, 2009, we had $300 million of unused availability on our revolving credit facility and over $90 million of cash on hand.

As of September 30, 2009, PVR had outstanding borrowings of $628.1 million under its $800 million revolving credit facility with remaining revolver borrowing capacity of $170.3 million.  The $60.0 million increase in outstanding PVR borrowings as compared to $568.0 million outstanding as of December 31, 2008 was primarily due to PVR capital expenditures during the first nine months of 2009.

Consolidated interest expense increased from $13.2 million in the third quarter of 2008 to $22.8 million in the third quarter of 2009.  The increase was due to a higher interest rate on the senior unsecured notes PVA issued in June 2009 and higher average level of outstanding borrowings during the third quarter of 2009 as compared to the prior year quarter.

Due to decreases in natural gas and crude oil prices experienced during the third quarter,the mark-to-market valuation of our and PVR’s open hedging positions resulted in derivatives income of $2.5 million in the third quarter as compared to derivatives income of $125.1 million in the prior year quarter.  Included in derivatives income for the third quarter of 2009 was $0.3 million of income related to our oil and gas segment and $2.8 million of expense related to PVR.  Third quarter 2009 cash settlements of our oil and gas derivatives resulted in net cash receipts of $15.8 million, as compared to $5.7 million of net cash payments in the same quarter of 2008.  PVR’s third quarter 2009 cash settlements of commodity and interest rate derivatives result in net cash payments of $0.3 million, as compared to $14.1 million of net cash payments in the same quarter of 2008.

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 operational update, are meant to provide guidance only and are subject to revision as our and PVR’s operating environments change.

Third Quarter 2009 Financial and Operational Results Conference Call

A conference call and webcast, during which management will discuss third quarter 2009 financial and operational results, is scheduled for Thursday, November 5, 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 1-866-630-9986 five to ten minutes before the scheduled start of the conference call and using the passcode 4836740, 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 will be available approximately two hours after the call for two weeks by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 4836740.  In addition, an on-demand replay of the webcast will also be available for two weeks at PVG’s or PVR’s websites beginning 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 the East Texas, Mississippi, the Mid-Continent region and the Appalachian Basin.  We also own approximately 51 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 write-downs 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; whether the sale of our Gulf Coast assets closes during the fourth quarter and at the anticipated price; operating risks, including unanticipated geological problems, incidental to our business and to PVR’s coal or natural gas midstream businesses; 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 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						Nine Months Ended
	September 30,						September 30,
	2009			2008 (a)			2009			2008 (a)
Revenues
Natural gas	$	36,654		$	101,911		$	129,305		$	295,636
Crude oil		13,259			13,764			31,412			37,442
Natural gas liquids (NGLs)		2,847			10,481			10,553			18,887
Natural gas midstream		102,262			184,914			289,123			494,260
Coal royalties		29,821			33,308			90,448			88,911
Gain on sale of property and equipment		1,945			31,279			1,918			31,335
Other		8,375			9,955			25,481			28,690
Total revenues		195,163			385,612			578,240			995,161
Expenses
Cost of midstream gas purchased		77,248			155,564			228,579			408,247
Operating		21,167			23,437			66,517			66,653
Exploration		12,405			8,346			34,587			19,765
Exploration - drilling rig standby charges - (b)		3,712			-			20,314			-
Taxes other than income		5,294			7,671			16,656			23,325
General and administrative (excluding equity compensation)		16,309			16,211			47,481			49,299
Equity-based compensation - (c)		3,637			2,078			11,306			5,707
Depreciation, depletion and amortization		57,869			49,978			173,160			133,481
Impairments on assets held for sale		87,900			-			87,900			-
Impairments		4,453			-			8,928			-
Loss on sale of assets		-			-			1,599			-
Total expenses		289,994			263,285			697,027			706,477
Operating income (loss)		(94,831	)		122,327			(118,787	)		288,684
Other income (expense)
Interest expense		(22,784	)		(13,221	)		(50,332	)		(35,313	)
Derivatives		(2,529	)		125,132			8,478			(4,387	)
Other		348			(4,088	)		2,274			(782	)
Income (loss) before income taxes and noncontrolling interests		(119,796	)		230,150			(158,367	)		248,202
Income tax benefit (expense)		50,405			(78,921	)		69,587			(74,352	)
Net income (loss)	$	(69,391	)	$	151,229		$	(88,780	)	$	173,850
Less net income attributable to noncontrolling interests		(10,509	)		(28,276	)		(20,512	)		(52,252	)
Income (loss) attributable to PVA	$	(79,900	)	$	122,953		$	(109,292	)	$	121,598
Income (loss) per share attributable to PVA
Basic	$	1.76		$	2.94		$	2.52		$	2.91
Diluted	$	1.76		$	2.88		$	2.52		$	2.88
Weighted average shares outstanding, basic		45,427			41,881			43,324			41,715
Weighted average shares outstanding, diluted		45,427			42,544			43,324			42,028
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Production
Natural gas (MMcf)		10,634			10,046			33,858			29,869
Crude oil (MBbls)		202			117			588			331
NGLs (MBbls)		94			157			381			300
Total natural gas, crude oil and NGL production (MMcfe)		12,410			11,690			39,672			33,655
Prices
Natural gas ($ per Mcf)	$	3.45		$	10.14		$	3.82		$	9.90
Crude oil ($ per Bbl)	$	65.64		$	117.64		$	53.42		$	113.12
NGLs ($ per Bbl)	$	30.29		$	66.76		$	27.70		$	62.96

(a) As a result of adopting accounting guidance 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 accounting guidance of share-based payments.

PENN VIRGINIA CORPORATION

CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

	September 30,		December 31,
	2009		2008
Assets
Current assets	$	293,483	$	263,518
Net property and equipment		2,372,323		2,512,177
Other assets		235,463		220,870
Total assets	$	2,901,269	$	2,996,565
Liabilities and shareholders' equity
Current liabilities	$	145,356	$	247,594
Long-term debt of PVR		628,100		568,100
Revolving credit facility		-		332,000
Senior notes		291,432		-
Convertible notes		204,935		199,896
Other liabilities and deferred taxes		268,834		312,645
PVA shareholders' equity		1,029,381		1,039,103
Noncontrolling interests		333,231		297,227
Total shareholders' equity		1,362,612		1,336,330
Total liabilities and shareholders' equity	$	2,901,269	$	2,996,565

CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Cash flows from operating activities
Net income (loss)	$	(69,391	)	$	151,229		$	(88,780	)	$	173,850
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		57,869			49,978			173,160			133,481
Impairments		92,353			-			96,828			-
Derivative contracts:
Total derivative losses (gains)		6,312			(123,628	)		(2,821	)		8,516
Cash receipts (payments) to settle derivatives		15,507			(19,755	)		51,936			(46,740	)
Deferred income taxes		(51,928	)		61,552			(70,728	)		60,105
Dry hole and unproved leasehold expense		10,593			5,520			30,476			14,992
Other		2,685			(27,374	)		16,064			(26,118	)
Operating cash flow  (see attached table
"Certain Non-GAAP Financial Measures")		64,000			97,522			206,135			318,086
Changes in operating assets and liabilities		20,046			(5,727	)		15,888			(41,399	)
Net cash provided by operating activities		84,046			91,795			222,023			276,687
Cash flows from investing activities
Acquisitions		(32,068	)		(162,078	)		(38,261	)		(278,185	)
Additions to property and equipment		(25,363	)		(162,857	)		(218,558	)		(392,031	)
Other		2,876			33,215			8,698			33,954
Net cash used in investing activities		(54,555	)		(291,720	)		(248,121	)		(636,262	)
Cash flows from financing activities
Dividends paid		(2,559	)		(2,351	)		(7,278	)		(7,037	)
Distributions paid to noncontrolling interest holders		(18,455	)		(17,917	)		(55,365	)		(45,829	)
Proceeds from (repayments of) bank borrowings		-			46,431			(7,542	)		46,431
Net proceeds from (repayments of) PVA borrowings		(70,000	)		(25,000	)		(332,000	)		58,000
Net proceeds from PVR borrowings		31,000			176,600			60,000			146,000
Net proceeds from issuance of PVA senior notes		-			-			291,009			-
Net proceeds from issuance of PVR partners' capital		-			-			-			138,015
Net proceeds from sale of PVG units		118,080			-			118,080			-
Net proceeds from issuance of PVA equity		-			-			64,835			-
Other		(860	)		(2,311	)		(18,945	)		8,475
Net cash provided by financing activities		57,206			175,452			112,794			344,055
Net increase (decrease) in cash and cash equivalents		86,697			(24,473	)		86,696			(15,520	)
Cash and cash equivalents - beginning of period		18,337			43,480			18,338			34,527
Cash and cash equivalents - end of period	$	105,034		$	19,007		$	105,034		$	19,007

PENN VIRGINIA CORPORATION

QUARTERLY SEGMENT INFORMATION - unaudited

(in thousands except where noted)

							Coal and Natural
Three Months Ended September 30, 2009	Oil and Gas						Resource		Natural Gas
	Amount			per Mcfe (a)			Management		Midstream		Other			Consolidated
Production
Total natural gas, crude oil and NGLs (MMcfe)		12,410
Natural gas (MMcf)		10,634
Crude oil (MBbls)		202
NGLs (MBbls)		94
Coal royalty tons (thousands of tons)								8,387
Midstream system throughput volumes (MMcf)										29,811
Revenues
Natural gas	$	36,654		$	3.45		$	-	$	-	$	-		$	36,654
Crude oil		13,259			65.64			-		-		-			13,259
NGLs		2,847			30.29			-		-		-			2,847
Natural gas midstream		-						-		118,443		(16,181	)		102,262
Coal royalties		-						29,821		-		-			29,821
Gain on sale of property and equipment		1,945						-		-		-			1,945
Other		1,043						5,358		2,003		(29	)		8,375
Total revenues		55,748			4.49			35,179		120,446		(16,210	)		195,163
Expenses
Cost of midstream gas purchased		-						-		92,355		(15,107	)		77,248
Operating expense		13,277			1.07			2,146		6,884		(1,140	)		21,167
Exploration		12,405			1.00			-		-		-			12,405
Exploration - drilling rig standby charges		3,712			0.30			-		-		-			3,712
Taxes other than income		4,186			0.34			421		584		103			5,294
General and administrative		5,133			0.41			3,388		4,180		7,245			19,946
Depreciation, depletion and amortization		39,326			3.17			7,999		9,852		692			57,869
Impairments on assets held for sale		87,900			7.08			-		-		-			87,900
Impairments		4,453			0.36			-		-		-			4,453
Total expenses		170,392			13.73			13,954		113,855		(8,207	)		289,994
Operating income (loss)	$	(114,644	)	$	(9.24	)	$	21,225	$	6,591	$	(8,003	)	$	(94,831	)
Additions to property and equipment	$	18,059					$	140	$	39,031	$	201		$	57,431

					Coal and Natural
Three Months Ended September 30, 2008	Oil and Gas				Resource		Natural Gas
	Amount		per Mcfe (a)		Management		Midstream		Other			Consolidated
Production
Total natural gas, crude oil and NGLs (MMcfe)		11,690
Natural gas (MMcf)		10,046
Crude oil (MBbls)		117
NGLs (MBbls)		157
Coal royalty tons (thousands of tons)						8,496
Midstream system throughput volumes (MMcf)								27,744
Revenues
Natural gas	$	101,911	$	10.14	$	-	$	-	$	-		$	101,911
Crude oil		13,764		117.64		-		-		-			13,764
NGLs		10,481		66.76		-		-		-			10,481
Natural gas midstream		-				-		241,282		(56,368	)		184,914
Coal royalties		-				33,308		-		-			33,308
Gain on sale of property and equipment		30,509				770							31,279
Other		60				7,582		2,334		(21	)		9,955
Total revenues		156,725		13.41		41,660		243,616		(56,389	)		385,612
Expenses
Cost of midstream gas purchased		-				-		211,262		(55,698	)		155,564
Operating expense		15,067		1.29		2,877		6,164		(671	)		23,437
Exploration		8,346		0.71		-		-		-			8,346
Taxes other than income		6,537		0.56		373		596		165			7,671
General and administrative		5,122		0.44		3,321		3,757		6,089			18,289
Depreciation, depletion and amortization		32,665		2.79		8,794		8,109		410			49,978
Total expenses		67,737		5.79		15,365		229,888		(49,705	)		263,285
Operating income (loss)	$	88,988	$	7.62	$	26,295	$	13,728	$	(6,684	)	$	122,327
Additions to property and equipment	$	213,573			$	497	$	110,606	$	259		$	324,935

(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)

							Coal and Natural
Nine Months Ended September 30, 2009	Oil and Gas						Resource		Natural Gas
	Amount			per Mcfe (a)			Management		Midstream		Other			Consolidated
Production
Total natural gas, crude oil and NGLs (MMcfe)		39,672
Natural gas (MMcf)		33,858
Crude oil (MBbls)		588
NGLs (MBbls)		381
Coal royalty tons (thousands of tons)								25,874
Midstream system throughput volumes (MMcf)										93,433
Revenues
Natural gas	$	129,305		$	3.82		$	-	$	-	$	-		$	129,305
Crude oil		31,412			53.42			-		-		-			31,412
NGLs		10,553			27.70			-		-		-			10,553
Natural gas midstream		-						-		348,882		(59,759	)		289,123
Coal royalties		-						90,448		-		-			90,448
Gain on sale of property and equipment		1,918						-		-		-			1,918
Other		2,904						18,127		4,346		104			25,481
Total revenues		176,092			4.44			108,575		353,228		(59,655	)		578,240
Expenses
Cost of midstream gas purchased		-						-		285,129		(56,550	)		228,579
Operating expense		42,788			1.08			6,580		20,358		(3,209	)		66,517
Exploration		34,587			0.87			-		-		-			34,587
Exploration - drilling rig standby charges		20,314			0.51			-		-		-			20,314
Taxes other than income		12,756			0.32			1,146		2,062		692			16,656
General and administrative		15,970			0.40			10,760		12,661		19,396			58,787
Depreciation, depletion and amortization		119,242			3.04			23,557		28,414		1,947			173,160
Impairments on assets held for sale		87,900			2.22			-		-		-			87,900
Impairments		8,928			0.23			-		-		-			8,928
Other		1,599			0.04			-		-		-			1,599
Total expenses		344,084			8.67			42,043		348,624		(37,724	)		697,027
Operating income (loss)	$	(167,992	)	$	(4.23	)	$	66,532	$	4,604	$	(21,931	)	$	(118,787	)
Additions to property and equipment	$	181,873					$	2,046	$	71,245	$	1,655		$	256,819

					Coal and Natural
Nine Months Ended September 30, 2008	Oil and Gas				Resource		Natural Gas
	Amount		per Mcfe (a)		Management		Midstream		Other			Consolidated
Production
Total natural gas, crude oil and NGLs (MMcfe)		33,655
Natural gas (MMcf)		29,869
Crude oil (MBbls)		331
NGLs (MBbls)		300
Coal royalty tons (thousands of tons)						24,975
Midstream system throughput volumes (MMcf)								68,915
Revenues
Natural gas	$	295,636	$	9.90	$	-	$	-	$	-		$	295,636
Crude oil		37,442		113.12		-		-		-			37,442
NGLs		18,887		62.96		-		-		-			18,887
Natural gas midstream		-				-		601,127		(106,867	)		494,260
Coal royalties		-				88,911		-		-			88,911
Gain on sale of property and equipment		30,543				-		-		-			30,543
Other		883				22,099		6,458		42			29,482
Total revenues		383,391		11.39		111,010		607,585		(106,825	)		995,161
Expenses
Cost of midstream gas purchased		-				-		513,778		(105,531	)		408,247
Operating expense		43,370		1.29		9,522		15,031		(1,270	)		66,653
Exploration		19,765		0.59		-		-		-			19,765
Taxes other than income		19,480		0.58		1,115		1,902		828			23,325
General and administrative		14,869		0.44		9,780		10,559		19,798			55,006
Depreciation, depletion and amortization		90,849		2.70		22,733		18,589		1,310			133,481
Total expenses		188,333		5.60		43,150		559,859		(84,865	)		706,477
Operating income (loss)	$	195,058	$	5.79	$	67,860	$	47,726	$	(21,960	)	$	288,684
Additions to property and equipment	$	422,975			$	25,186	$	220,997	$	1,058		$	670,216

(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						Nine Months Ended
	September 30,						September 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	$	84,046		$	91,795		$	222,023		$	276,687
Adjustments:
Changes in operating assets and liabilities		(20,046	)		5,727			(15,888	)		41,399
Operating cash flow (a)	$	64,000		$	97,522		$	206,135		$	318,086
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	$	(79,900	)	$	122,953		$	(109,292	)	$	121,598
Adjustments for derivatives:
Derivative losses (gains) included in income		6,312			(123,628	)		(2,821	)		8,516
Cash receipts (payments) to settle derivatives		15,507			(19,755	)		51,936			(46,740	)
Adjustment for drilling rig standby charges		3,712			-			20,314			-
Adjustment for impairments		92,353			-			96,828			-
Adjustment for net gains on sale of assets		(1,945	)		(31,279	)		(319	)		(31,335	)
Impact of adjustments on noncontrolling interests		(2,579	)		16,755			(9,494	)		13,649
Impact of adjustments on income taxes		(44,621	)		49,139			(60,859	)		9,339
	$	(11,161	)	$	14,185		$	(13,707	)	$	75,027
Less: Portion of subsidiary net income (loss) allocated to undistributed share-based compensation awards, net of taxes		(44	)		(219	)		(68	)		(418	)
Net income (loss) attributable to PVA, as adjusted (b)	$	(11,205	)	$	13,966		$	(13,775	)	$	74,609
Net income (loss) attributable to PVA, as adjusted, per share, diluted	$	(0.25	)	$	0.33		$	(0.32	)	$	1.78

(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 (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, gains and losses on the sale of assets, and net income of PVR allocated to unvested PVR restricted units awarded as equity compensation 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 (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

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 September 30, 2009									Three Months Ended September 30, 2008
	As Reported			Adjustments			As Adjusted			As Reported			Adjustments			As Adjusted
Revenues
Natural gas	$	36,654		$	-		$	36,654		$	101,911		$	-		$	101,911
Crude oil		13,259			-			13,259			13,764			-			13,764
NGLs		2,847			-			2,847			10,481			-			10,481
Natural gas midstream		102,262			(102,262	)		-			184,914			(184,914	)		-
Coal royalties		29,821			(29,821	)		-			33,308			(33,308	)		-
Other		10,320			(7,361	)		2,959			41,234			(10,686	)		30,548
Total revenues		195,163			(139,444	)		55,719			385,612			(228,908	)		156,704
Expenses
Cost of midstream gas purchased		77,248			(77,248	)		-			155,564			(155,564	)		-
Operating		21,167			(9,030	)		12,137			23,437			(8,371	)		15,066
Exploration		12,405			-			12,405			8,346			-			8,346
Exploration - drilling rig standby charges		3,712			-			3,712			-			-			-
Taxes other than income		5,294			(1,005	)		4,289			7,671			(969	)		6,702
General and administrative		19,946			(8,481	)		11,465			18,289			(7,618	)		10,671
Depreciation, depletion and amortization		57,869			(17,851	)		40,018			49,978			(16,903	)		33,075
Impairments on properties held for sale		87,900			-			87,900			-			-			-
Impairments		4,453			-			4,453			-			-			-
Loss on sale of assets		-			-			-			-			-			-
Total expenses		289,994			(113,615	)		176,379			263,285			(189,425	)		73,860
Operating income (loss)		(94,831	)		(25,829	)		(120,660	)		122,327			(39,483	)		82,844
Other income (expense)
Interest expense		(22,784	)		6,505			(16,279	)		(13,221	)		7,060			(6,161	)
Derivatives		(2,529	)		2,810			281			125,132			(15,742	)		109,390
Equity earnings in PVG and PVR		-			6,349			6,349			-			15,771			15,771
Other		348			(344	)		4			(4,088	)		4,118			30
Income (loss) before taxes and noncontrolling interests		(119,796	)		(10,509	)		(130,305	)		230,150			(28,276	)		201,874
Income tax benefit (expense)		50,405			-			50,405			(78,921	)		-			(78,921	)
Net income (loss)		(69,391	)		(10,509	)		(79,900	)		151,229			(28,276	)		122,953
Less net income attributable to noncontrolling interests		(10,509	)		10,509			-			(28,276	)		28,276			-
Net income (loss) attributable to PVA	$	(79,900	)	$	-		$	(79,900	)	$	122,953		$	-		$	122,953

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	As Reported			Adjustments			As Adjusted			As Reported			Adjustments			As Adjusted
Revenues
Natural gas	$	129,305		$	-		$	129,305		$	295,636		$	-		$	295,636
Crude oil		31,412			-			31,412			37,442			-			37,442
NGLs		10,553			-			10,553			18,887			-			18,887
Natural gas midstream		289,123			(289,123	)		-			494,260			(494,260	)		-
Coal royalties		90,448			(90,448	)		-			88,911			(88,911	)		-
Other		27,399			(22,473	)		4,926			60,025			(28,557	)		31,468
Total revenues		578,240			(402,044	)		176,196			995,161			(611,728	)		383,433
Expenses
Cost of midstream gas purchased		228,579			(228,579	)		-			408,247			(408,247	)		-
Operating		66,517			(26,938	)		39,579			66,653			(23,217	)		43,436
Exploration		34,587			-			34,587			19,765			-			19,765
Exploration - drilling rig standby charges		20,314			-			20,314			-			-			-
Taxes other than income		16,656			(3,208	)		13,448			23,325			(3,017	)		20,308
General and administrative		58,787			(25,433	)		33,354			55,006			(22,057	)		32,949
Depreciation, depletion and amortization		173,160			(51,971	)		121,189			133,481			(41,322	)		92,159
Impairments on assets held for sale		87,900			-			87,900			-			-			-
Impairments		8,928			-			8,928			-			-			-
Loss on sale of assets		1,599			-			1,599			-			-			-
Total expenses		697,027			(336,129	)		360,898			706,477			(497,860	)		208,617
Operating income (loss)		(118,787	)		(65,915	)		(184,702	)		288,684			(113,868	)		174,816
Other income (expense)
Interest expense		(50,332	)		18,486			(31,846	)		(35,313	)		17,366			(17,947	)
Derivatives		8,478			12,005			20,483			(4,387	)		6,424			2,037
Equity earnings in PVG and PVR		-			15,932			15,932			-			34,754			34,754
Other		2,274			(1,020	)		1,254			(782	)		3,072			2,290
Income (loss) before taxes and noncontrolling interests		(158,367	)		(20,512	)		(178,879	)		248,202			(52,252	)		195,950
Income tax benefit (expense)		69,587			-			69,587			(74,352	)		-			(74,352	)
Net income (loss)		(88,780	)		(20,512	)		(109,292	)		173,850			(52,252	)		121,598
Less net income attributable to noncontrolling interests		(20,512	)		20,512			-			(52,252	)		52,252			-
Net income (loss) attributable to PVA	$	(109,292	)	$	-		$	(109,292	)	$	121,598		$	-		$	121,598

(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):

	September 30, 2009							December 31, 2008
	As Reported		Adjustments			As Adjusted		As Reported		Adjustments			As Adjusted
Assets
Current assets	$	293,483	$	(92,843	)	$	200,640	$	263,518	$	(126,299	)	$	137,219
Net property and equipment		2,372,323		(909,994	)		1,462,329		2,512,177		(895,119	)		1,617,058
Equity investment in PVG and PVR		-		158,276			158,276		-		248,211			248,211
Other assets		235,463		(215,937	)		19,526		220,870		(206,256	)		14,614
Total assets	$	2,901,269	$	(1,060,498	)	$	1,840,771	$	2,996,565	$	(979,463	)	$	2,017,102
Liabilities and shareholders' equity
Current liabilities	$	145,356	$	(70,873	)	$	74,483	$	247,594	$	(89,908	)	$	157,686
Long-term debt		1,124,467		(628,100	)		496,367		1,099,996		(568,100	)		531,896
Other liabilities and deferred taxes		268,834		(28,294	)		240,540		312,645		(24,228	)		288,417
														-
PVA shareholders' equity		1,029,381		-			1,029,381		1,039,103		-			1,039,103
Noncontrolling interests		333,231		(333,231	)		-		297,227		(297,227	)		-
Total shareholders' equity		1,362,612		(333,231	)		1,029,381		1,336,330		(297,227	)		1,039,103
Total liabilities and shareholders' equity	$	2,901,269	$	(1,060,498	)	$	1,840,771	$	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 September 30, 2009									Three Months Ended September 30, 2008
	As Reported			Adjustments			As Adjusted			As Reported			Adjustments			As Adjusted
Cash flows from operating activities
Net income (loss)	$	(69,391	)	$	-		$	(69,391	)	$	151,229		$	-		$	151,229
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		57,869			(17,851	)		40,018			49,978			(16,903	)		33,075
Impairments		92,353			-			92,353			-			-			-
Derivative contracts:
Total derivative losses (gains)		6,312			(3,668	)		2,644			(123,628	)		14,239			(109,389	)
Cash receipts (payments) to settle derivatives		15,507			314			15,821			(19,755	)		14,054			(5,701	)
Deferred income taxes		(51,928	)					(51,928	)		61,552			-			61,552
Dry hole and unproved leasehold expense		10,593			-			10,593			5,520			-			5,520
Investment in PVG and PVR		-			(18,470	)		(18,470	)		-			(44,047	)		(44,047	)
Cash distributions from PVG and PVR		-			11,868			11,868			-			10,967			10,967
Other		2,685			(1,232	)		1,453			(27,374	)		1,130			(26,244	)
Operating cash flow		64,000			(29,039	)		34,961			97,522			(20,560	)		76,962
Changes in operating assets and liabilities		20,046			(1,892	)		18,154			(5,727	)		10,853			5,126
Net cash provided by operating activities		84,046			(30,931	)		53,115			91,795			(9,707	)		82,088
Net cash used in investing activities		(54,555	)		38,871			(15,684	)		(291,720	)		171,871			(119,849	)
																	-
Net cash provided by financing activities		57,206			(12,545	)		44,661			175,452			(155,229	)		20,223
Net increase (decrease) in cash and cash equivalents		86,697			(4,605	)		82,092			(24,473	)		6,935			(17,538	)
Cash and cash equivalents-beginning balance		18,337			(17,093	)		1,244			43,480			(25,942	)		17,538
Cash and cash equivalents-ending balance	$	105,034		$	(21,698	)	$	83,336		$	19,007		$	(19,007	)	$	-

	Nine Months Ended September 30, 2009									Nine Months Ended September 30, 2008
	As Reported			Adjustments			As Adjusted			As Reported			Adjustments			As Adjusted
Cash flows from operating activities
Net income (loss)	$	(88,780	)	$	-		$	(88,780	)	$	173,850		$	-		$	173,850
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		173,160			(51,971	)		121,189			133,481			(41,322	)		92,159
Impairments		96,828			-			96,828			-			-			-
Derivative contracts:
Total derivative losses (gains)		(2,821	)		(14,234	)		(17,055	)		8,516			(10,552	)		(2,036	)
Cash settlements of derivatives		51,936			(4,135	)		47,801			(46,740	)		33,279			(13,461	)
Deferred income taxes		(70,728	)		-			(70,728	)		60,105			-			60,105
Dry hole and unproved leasehold expense		30,476			-			30,476			14,992			-			14,992
Investment in PVG and PVR		-			(40,191	)		(40,191	)		-			(87,006	)		(87,006	)
Cash distributions from PVG and PVR		-			34,932			34,932			-			32,447			32,447
Other		16,064			(1,263	)		14,801			(26,118	)		1,209			(24,909	)
Operating cash flow		206,135			(76,862	)		129,273			318,086			(71,945	)		246,141
Changes in operating assets and liabilities		15,888			(3,540	)		12,348			(41,399	)		11,277			(30,122	)
Net cash provided by operating activities		222,023			(80,402	)		141,621			276,687			(60,668	)		216,019
Net cash used in investing activities		(248,121	)		72,419			(175,702	)		(636,262	)		306,276			(329,986	)
																	-
Net cash provided by financing activities		112,794			4,623			117,417			344,055			(234,112	)		109,943
Net increase (decrease) in cash and cash equivalents		86,696			(3,360	)		83,336			(15,520	)		11,496			(4,024	)
Cash and cash equivalents-beginning balance		18,338			(18,338	)		-			34,527			(30,503	)		4,024
Cash and cash equivalents-ending balance	$	105,034		$	(21,698	)	$	83,336		$	19,007		$	(19,007	)	$	-

(a) Equity method balance sheets represent consolidated balance sheets, minus 100% of PVG’s consolidated balance sheets, excluding noncontrolling interests 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 interests 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			Third Quarter			YTD			Full-Year
Oil & Gas Segment:	2009			2009			2009			2009			2009 Guidance
Production:
Natural gas (Bcf) - (a)		11.8			11.4			10.6			33.8			42.2	-	43.5
Crude oil (MBbls) - (a)		171			215			202			588			740	-	760
NGLs (MBbls)		147			140			94			381			470	-	490
Equivalent production (Bcfe)		13.7			13.6			12.4			39.7			49.5	-	51.0
Equivalent daily production (MMcfe per day)		152.3			149.5			134.9			145.3			135.5	-	139.7
Expenses:
Cash operating expenses ($ per Mcfe)	$	1.80			1.79			1.82			1.80			1.85	-	1.90
Exploration	$	21.3			17.5			16.1			54.9			63.0	-	66.0
Depreciation, depletion and amortization ($ per Mcfe)	$	2.92			2.94			3.17			3.04			2.95	-	3.05
Impairments	$	1.2			3.3			92.4			96.8			96.8	-	96.8
Loss on sale of assets	$	-			1.6			-			1.6			1.6	-	2.0
Capital expenditures:
Development drilling	$	76.5			37.3			8.3			122.1			155.0	-	165.0
Exploratory drilling	$	1.5			-			0.7			2.2			4.0	-	4.5
Pipeline, gathering, facilities	$	5.1			2.4			0.9			8.4			9.0	-	10.0
Seismic	$	0.7			0.4			0.1			1.2			2.0	-	2.2
Lease acquisition, field projects and other	$	1.8			2.8			5.8			10.4			46.0	-	47.0
Total segment capital expenditures	$	85.6			42.9			15.8			144.3			216.0	-	228.7
Coal and Natural Resource Segment (PVR):
Coal royalty tons (millions)		8.7			8.7			8.4			25.8			33.0	-	34.0
Revenues:
Average coal royalties per ton	$	3.50			3.43			3.56			3.50			3.35	-	3.45
Average coal royalties per ton, net of coal royalties expense	$	3.36			3.25			3.37			3.33			3.25	-	3.35
Other	$	7.6			5.1			5.4			18.1			23.0	-	24.0
Expenses:
Cash operating expenses	$	5.9			6.6			6.0			18.5			23.5	-	24.0
Depreciation, depletion and amortization	$	7.4			8.2			8.0			23.6			31.0	-	32.0
Capital expenditures:
Expansion and acquisitions	$	1.3			0.6			0.1			2.0			2.0	-	3.0
Other capital expenditures	$	-			-			-			-			0.5	-	1.0
Total segment capital expenditures	$	1.3			0.6			0.1			2.0			2.5	-	4.0
Natural Gas Midstream Segment (PVR):
System throughput volumes (MMcf per day) (b)		359			344			324			342			330	-	340
Expenses:
Cash operating expenses	$	11.8			11.6			11.6			35.0			48.0	-	50.0
Depreciation, depletion and amortization	$	9.1			9.5			9.8			28.4			38.0	-	39.0
Capital expenditures:
Expansion and acquisitions	$	11.2			10.3			34.0			55.5			65.0	-	70.0
Maintenance capital expenditures	$	3.3			1.4			1.4			6.1			7.0	-	9.0
Total segment capital expenditures	$	14.5			11.7			35.4			61.6			72.0	-	79.0
Corporate and Other:
General and administrative expense - PVA	$	5.2			5.8			6.4			17.4			23.0	-	24.0
General and administrative expense - PVG	$	0.5			0.6			0.9			2.0			2.4	-	2.8
Interest expense:
PVA end of period debt outstanding	$	591.5			564.3			496.3
PVA average interest rate (c)		4.3	%		6.0	%		9.8	%
PVR end of period debt outstanding	$	595.1			597.1			628.1
PVR average interest rate		3.9	%		4.2	%		4.2	%
Income tax rate		38.8	%		39.7	%		38.7	%		38.9	%
Cash distributions received from PVG and PVR	$	11.5			11.6			11.5			34.6
Other capital expenditures	$	0.6			0.9			0.2			1.7			2.0	-	2.5

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)

Notes to Guidance Table:

(a) The following table shows our current derivative positions in the oil and gas segment as of September 30, 2009:

			Weighted Average Price
	Average Volume Per Day		Additional Put Option		Floor		Ceiling
Natural Gas Costless Collars	(MMBtu)		($ per MMBtu)
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		30,000				5.67		7.58
Third quarter 2011		30,000				5.67		7.58
Natural Gas Three-way Collars	(MMBtu)		($ per MMBtu)
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)
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 Three-way Collars (1)	(barrels)		($ per barrel)
Fourth quarter 2009		500		80.00		110.00		179.00
Crude Oil Swaps	(barrels)		($ per barrel)
Fourth quarter 2009		500				59.25
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

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)

(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 September 30, 2009:

	Average			Weighted Average Price
	Volume		Swap	Additional
	Per Day		Price	Put Option		Put		Call
Crude Oil Three-Way Collar	(barrels)					($ per barrel)
Fourth quarter 2009		1,000			70.00		90.00		119.25
Frac Spread Collar (1)	(MMBtu)					($ per MMBtu)
Fourth quarter 2009		6,000					9.09		13.94
Crude Oil Collar	(barrels)					($ per barrel)
First quarter 2010 through fourth quarter 2010		750					70.00		81.25
Crude Oil Collar	(barrels)					($ per barrel)
First quarter 2010 through fourth quarter 2010		1,000					68.00		80.00
Natural Gas Purchase Swap	(MMBtu)		($ per MMbtu)
First quarter 2010 through fourth quarter 2010		5,000	5.815

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.

(c)  Third quarter 2009 average interest rate excludes effect of $2.4 million reclassification from accumulated other comprehensive income related to interest rate swaps.