BAYTEX ENERGY USA, INC. - Quarter Report: 2010 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2010

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

For the transition period from _______ to _______

Commission File Number: 1-13283

PENN VIRGINIA CORPORATION

(Exact name of registrant as specified in its charter)

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

FOUR RADNOR CORPORATE CENTER, SUITE 200

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

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

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

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

Large accelerated filer	x	Accelerated filer	¨

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

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

As of October 29, 2010, 45,544,092 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2010

Table of Contents

Item		Page
	Part I - Financial Information

1.	Financial Statements
	Condensed Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2010 and 2009	1
	Condensed Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009	2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009	3
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	4
	2. Basis of Presentation	4
	3. Property Acquisitions and Divestitures	4
	4. Discontinued Operations	5
	5. Derivative Financial Instruments	6
	6. Property and Equipment, net	9
	7. Long-Term Debt	9
	8. Additional Balance Sheet Detail	11
	9. Fair Value Measurements	12
	10. Shareholders’ Equity and Comprehensive Income	14
	11. Commitments and Contingencies	14
	12. Share-Based Compensation	15
	13. Restructuring Activities	15
	14. Impairments	15
	15. Interest Expense	16
	16. Earnings per Share	17
	17. New Accounting Standards	17

Forward-Looking Statements		18

2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview of Business	19
	Key Developments	20
	Results of Operations	21
	Liquidity and Capital Resources	32
	Environmental Matters	37
	Critical Accounting Estimates	37
	New Accounting Standards	38

3.	Quantitative and Qualitative Disclosures About Market Risk	38

4.	Controls and Procedures	39

	Part II - Other Information

6.	Exhibits	40

Signatures		41

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per share data)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenues
Natural gas	$	47,476		$	36,654		$	134,283		$	129,305
Crude oil		13,396			13,259			38,117			31,412
Natural gas liquids (NGLs)		7,459			2,847			14,987			10,553
Gain on sale of property and equipment		280			1,945			616			1,945
Other		342			1,014			2,116			2,981
Total revenues		68,953			55,719			190,119			176,196
Operating expenses
Lease operating		9,256			10,787			27,148			34,208
Gathering, processing and transportation		3,625			2,424			10,165			8,580
Production and ad valorem taxes		5,309			3,842			12,684			11,305
General and administrative		13,445			11,946			44,297			35,531
Exploration		22,020			16,117			37,590			54,901
Depreciation, depletion and amortization		33,224			40,319			95,358			122,095
Impairments		35,127			92,353			36,251			96,828
Other		-			-			465			1,599
Total operating expenses		122,006			177,788			263,958			365,047

Operating loss		(53,053	)		(122,069	)		(73,839	)		(188,851	)
Other income (expense)
Interest expense		(13,198	)		(16,279	)		(40,190	)		(31,846	)
Derivatives		15,113			281			44,410			20,483
Other		342			4			2,105			1,254
Loss from continuing operations before income taxes		(50,796	)		(138,063	)		(67,514	)		(198,960	)
Income tax benefit		20,637			53,351			27,024			77,399
Net loss from continuing operations		(30,159	)		(84,712	)		(40,490	)		(121,561	)
Income from discontinued operations, net of tax		-			15,321			33,482			32,781
Gain on sale of discontinued operations, net of tax		-			-			49,612			-
Net income (loss)		(30,159	)		(69,391	)		42,604			(88,780	)
Less net income attributable to noncontrolling interests
in discontinued operations		-			(10,509	)		(28,090	)		(20,512	)
Income (loss) attributable to Penn Virginia Corporation	$	(30,159	)	$	(79,900	)	$	14,514		$	(109,292	)

Earnings (loss) per share attributable to Penn Virginia Corporation - Basic:
Continuing operations	$	(0.66	)	$	(1.87	)	$	(0.89	)	$	(2.80	)
Discontinued operations		-			0.11			0.12			0.28
Gain on sale of discontinued operations		-			-			1.09			-
Net income (loss)	$	(0.66	)	$	(1.76	)	$	0.32		$	(2.52	)

Earnings (loss) per share attributable to Penn Virginia Corporation - Diluted:
Continuing operations	$	(0.66	)	$	(1.87	)	$	(0.89	)	$	(2.80	)
Discontinued operations		-			0.11			0.12			0.28
Gain on sale of discontinued operations		-			-			1.09			-
Net income (loss)	$	(0.66	)	$	(1.76	)	$	0.32		$	(2.52	)

Weighted average shares outstanding, basic		45,591			45,427			45,534			43,324
Weighted average shares outstanding, diluted		45,591			45,427			45,733			43,324

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)

	September 30,			December 31,
	2010			2009
Assets
Current assets
Cash and cash equivalents	$	204,452		$	79,017
Accounts receivable, net of allowance for doubtful accounts		58,483			43,157
Derivative assets		24,327			16,241
Assets held for sale		-			38,282
Other current assets		6,578			15,437
Current assets of discontinued operations		-			107,108
Total current assets		293,840			299,242
Property and equipment, net (successful efforts method)		1,657,683			1,479,452
Derivative assets		7,531			2,346
Other assets		21,369			24,124
Noncurrent assets of discontinued operations		-			1,083,343
Total assets	$	1,980,423		$	2,888,507

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	95,260		$	70,724
Derivative liabilities		503			4,896
Deferred income taxes		8,974			-
Income taxes payable		53,985			-
Current liabilities of discontinued operations		-			77,915
Total current liabilities		158,722			153,535
Other liabilities		20,083			20,711
Derivative liabilities		-			2,460
Deferred income taxes		294,203			328,238
Long-term debt		504,524			498,427
Noncurrent liabilities of discontinued operations		-			647,137

Commitments and contingencies

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; none issued
Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued
and outstanding of 45,541,521 and 45,386,004 as of September 30, 2010
and December 31, 2009, respectively		267			265
Paid-in capital		678,615			590,846
Retained earnings		325,981			319,167
Deferred compensation obligation		2,608			2,423
Accumulated other comprehensive loss		(1,460	)		(1,286	)
Treasury stock – 125,584 and 113,858 shares of common stock, at cost, as of
September 30, 2010 and December 31, 2009, respectively		(3,120	)		(3,327	)
Total Penn Virginia Corporation shareholders' equity		1,002,891			908,088
Noncontrolling interests in discontinued operations		-			329,911
Total shareholders’ equity		1,002,891			1,237,999
Total liabilities and shareholders’ equity	$	1,980,423		$	2,888,507

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities
Net income (loss)	$	42,604		$	(88,780	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Income from discontinued operations		(36,832	)		(40,593	)
Gain on sale of discontinued operations		(84,740	)		-
Depreciation, depletion and amortization		95,358			122,095
Impairments		36,251			96,828
Derivative contracts:
Total derivative gains		(44,410	)		(17,055	)
Cash receipts to settle derivatives		24,287			47,801
Deferred income taxes		6,149			(70,728	)
Gain on the sale of property and equipment, net		(151	)		(1,945	)
Dry hole and unproved leasehold expense		26,501			30,476
Non-cash interest expense		9,089			7,213
Share-based compensation		6,400			7,445
Other, net		(341	)		2,088
Changes in operating assets and liabilities		(11,290	)		12,348
Net cash provided by operating activities		68,875			107,193

Cash flows from investing activities
Capital expenditures - property and equipment		(313,710	)		(183,528	)
Proceeds from the sale of PVG units, net (Note 3)		139,120			-
Proceeds from the sale of property and equipment, net		25,172			7,815
Other, net		1,192			11
Net cash used in investing activities		(148,226	)		(175,702	)

Cash flows from financing activities
Dividends paid		(7,700	)		(7,278	)
Distributions received from discontinued operations		11,218			34,932
Repayments of short-term borrowings		-			(7,542	)
Repayment of revolving credit facility borrowings		-			(332,000	)
Proceeds from issuance of Senior notes, net		-			291,009
Proceeds from the issuance of common stock, net		-			64,835
Proceeds from the sale of PVG units, net (Note 3)		199,125			118,080
Debt issuance costs paid		-			(9,687	)
Other, net		2,143			-
Net cash provided by financing activities		204,786			152,349

Cash flows from discontinued operations
Net cash provided by operating activities		77,759			114,830
Net cash used in investing activities		(18,112	)		(75,275	)
Net cash used in financing activities		(59,647	)		(39,555	)
Net cash provided by discontinued operations		-			-
Net increase in cash and cash equivalents		125,435			83,840
Cash and cash equivalents - beginning of period		79,017			-
Cash and cash equivalents - end of period	$	204,452		$	83,840

Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	22,646		$	12,863
Income taxes (net of refunds received)	$	25,168		$	1,906

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2010

(in thousands, except per share amounts)

1. Organization

Penn Virginia Corporation (“Penn Virginia,” the “Company,” “we,” “us” or “our”) is an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions including the Mid-Continent, East Texas, Appalachia and Mississippi.

Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P. (“PVR”), a publicly traded limited partnership formed by us in 2001 that is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR were held principally through our general and limited partner interests in Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded limited partnership formed by us in 2006. During June 2010, we disposed of our remaining ownership interests in PVG and, indirectly, our interests in PVR. The disposition transaction, as well as related transactions that took place earlier in 2010 and 2009, are more fully described in Note 3.

2. Basis of Presentation

Our Condensed Consolidated Financial Statements include the accounts of Penn Virginia and all of its subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Our Condensed Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Preparation of these statements involves the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our Condensed Consolidated Financial Statements have been included. Our Condensed Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and Notes included in our Annual Report on Form 10-K for the year ended December 31, 2009. Operating results for the nine months ended September 30, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

As a result of the aforementioned disposition of our interests in PVG, the presentation of our Condensed Consolidated Financial Statements and Notes is substantially different in format from certain previous filings as described in detail in Notes 3 and 4. In addition, certain amounts for the 2010 and 2009 periods were reclassified to conform to the current presentation.

Management has evaluated all activities of the Company through the date upon which the Condensed Consolidated Financial Statements were issued and concluded that no subsequent events have occurred that would require recognition in the Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.

3. Property Acquisitions and Divestitures

Property Acquisitions

Eagle Ford and Marcellus Shale Property Acquisitions

In August 2010, we acquired approximately 6,800 net acres in the Eagle Ford Shale play in Texas for approximately $31.1 million. The acreage includes over 40 horizontal well locations. We are the operator with a working interest of approximately 75% and a net revenue interest of approximately 57%. In May 2010, we acquired approximately 10,000 net acres with Marcellus Shale rights in Pennsylvania in two transactions for approximately $19.5 million. The first transaction included approximately 7,900 net acres with Marcellus Shale rights and approximately 23,000 net acres with deeper rights. In connection with this acquisition, we granted the seller a 1.5 percent overriding royalty interest on the acquired acreage. The second transaction included approximately 2,100 net acres with rights to the Marcellus Shale and all other formations.

Divestitures

PVG Unit Offerings

In September 2009, we sold 10 million common units of PVG (“PVG Common Units”) owned by us for proceeds of $118.1 million, net of offering costs, resulting in a reduction of our limited partner interest in PVG from 77.0% to 51.4%. In April 2010, we completed the sale of an additional 11.25 million PVG Common Units for proceeds of $199.1 million, net of offering costs, which further reduced our limited partner interest to 22.6%. On a combined basis, these transactions resulted in a $137.9 million increase to noncontrolling interests as well as a $114.8 million increase to additional paid-in capital, net of income tax effects of $64.5 million. Because we maintained a controlling financial interest in PVG, the proceeds received from these transactions, for accounting purposes, were treated as cash flows from financing activities on our Condensed Consolidated Statements of Cash Flows.

In June 2010, we completed the sale of our remaining PVG Common Units for $139.1 million, net of offering costs. Immediately prior to the closing of the June offering, we contributed 100% of the membership interests in PVG’s general partner to PVG, thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $49.6 million, net of income tax effects of $35.1 million, which is reported in the caption labeled “Gain on sale of discontinued operations, net of tax” on our Condensed Consolidated Statements of Income. Because we no longer held any interests in PVG, the proceeds received from this transaction, for accounting purposes, were treated as cash flows from investing activities on our Condensed Consolidated Statements of Cash Flows. Due to this divestiture of our interests in PVG, we deconsolidated PVG from our Condensed Consolidated Financial Statements. We have reported PVG’s results of operations and financial position as discontinued operations for the 2010 periods and comparative 2009 periods. Additional information with respect to discontinued operations is provided in Note 4.

Gulf Coast Properties

On December 23, 2009, we entered into purchase and sale agreements with a private company (the “Counterparty”) which resulted in the disposition of all of our oil and gas properties in the Gulf Coast region (southern Texas and Louisiana) in January 2010 for cash proceeds of $23.2 million, net of transaction costs and purchase and sale adjustments, and the exchange of certain oil and gas properties located in the Gwinville field in northern Mississippi valued at $8.2 million. The fair values of the Gulf Coast oil and gas properties, as well as liabilities attributable to the disposal group, were reported as assets and liabilities held for sale as of December 31, 2009. The fair value of the properties received from the Counterparty in the exchange was $8.2 million. An initial deposit of $2.3 million was received from the Counterparty in December 2009. This amount was included in accrued liabilities as of December 31, 2009. A loss on the sale of approximately $0.5 million was recognized in January 2010 as a component of operating expenses in connection with the closing.

Other Properties

During the quarter ended September 30, 2010, we received net proceeds of $1.9 million from the sale of various oil and gas properties located in North Dakota, West Virginia and Oklahoma.

4. Discontinued Operations

Income from discontinued operations represents the results of operations of PVG, which include the results of operations of PVR. Previously, the results of operations of PVG and PVR were presented as our coal and natural resource management and natural gas midstream segments, respectively. The disclosures for the 2010 period provided in the table below reflect the results of operations of PVG through the date of the disposition of our entire remaining interest in PVG on June 7, 2010.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2010		2009			2010			2009
Revenues	$	-	$	139,444		$	303,206		$	402,044

Income from discontinued operations before taxes	$	-	$	18,267		$	36,832		$	40,593
Income tax expense 1		-		(2,946	)		(3,350	)		(7,812	)
Income from discontinued operations, net of taxes	$	-	$	15,321		$	33,482		$	32,781

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

The following tables provide the detail of the assets and liabilities of discontinued operations as of December 31, 2009:

Current assets:			Noncurrent assets:
Cash and cash equivalents	$	19,314	Net property and equipment	$	872,906
Accounts receivable, net		81,647	Equity investments		87,601
Derivative assets		1,331	Intangibles, net		83,741
Inventory		1,832	Derivative assets		1,284
Other current assets		2,984	Other noncurrent assets		37,811
	$	107,108		$	1,083,343

Current liabilities:			Noncurrent liabilities:
Accounts payable	$	52,901	Other liabilities	$	22,752
Accrued liabilities		13,763	Derivative liabilities		4,285
Derivative liabilities		11,251	Long-term debt of PVR		620,100
	$	77,915		$	647,137

The following table summarizes the determination of the gain recognized on the disposition of PVG:

Cash proceeds, net of offering costs (8,827,429 units x $15.76 per unit)	$	139,120
Carrying value of noncontrolling interests in PVG at date of disposition		382,324
				521,444
Less: Carrying value of PVG's assets and liabilities at date of disposition				(436,704	)
				84,740
Income tax expense				(35,128	)
Gain on sale of discontinued operations, net of tax			$	49,612

We will have continuing involvement with PVR’s natural gas midstream segment through a number of existing agreements with various remaining terms. PVR will continue to provide marketing and gas gathering and processing services to the Company under certain of these agreements. We will continue to sell gas to PVR for resale at PVR’s Crossroads plant in east Texas. In addition, we and PVG have entered into transition service agreements attributable primarily to corporate and information technology functions. Through September 30, 2010, we have billed PVG for transition services in the amount of $0.7 million, net of amounts charged to us by PVG.

5. Derivative Financial Instruments

We utilize derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility as well as the volatility in interest rates attributable to our debt instruments. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, generally take the form of swaps and collars. Our derivative financial instruments are not designated as hedges.

Commodity Derivatives

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

The following table sets forth our oil and gas derivative positions as of September 30, 2010:

		Average						Fair Value
		Volume Per		Weighted Average Price				Asset
	Instrument	Day		Floor		Ceiling		(Liability)
Natural Gas:		(in MMBtu)
Fourth quarter 2010	Costless collars		50,000	$	5.65	$	8.77	$	7,854
First quarter 2011	Costless collars		50,000	$	5.65	$	8.77		6,396
Second quarter 2011	Costless collars		30,000	$	5.67	$	7.58		4,029
Third quarter 2011	Costless collars		30,000	$	5.67	$	7.58		3,807
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50		2,615
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		2,016
Second quarter 2012	Swaps		10,000	$	5.52				581
Third quarter 2012	Swaps		10,000	$	5.52				496

Crude Oil:		(barrels)
Fourth quarter 2010	Costless collars		500	$	60.00	$	74.75		(338	)
First quarter 2011	Costless collars		425	$	80.00	$	101.50		144
Second quarter 2011	Costless collars		425	$	80.00	$	101.50		152
Third quarter 2011	Costless collars		360	$	80.00	$	103.30		130
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		111

Settlements to be paid in subsequent period									-

Interest Rate Swaps

In 2006, we entered into interest rate swaps (“Previous Interest Rate Swaps”) with notional amounts of $50 million to establish fixed interest rates on a portion of the then outstanding borrowings under our revolving credit facility (“Revolver”) through December 2010. During the first quarter of 2009, we discontinued hedge accounting for all of the Previous Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Previous Interest Rate Swaps have been recognized in the Derivatives caption on our Condensed Consolidated Statements of Income.

As there are currently no amounts outstanding under the Revolver, we entered into an offsetting fixed-to-floating interest rate swap (“Offsetting Swap”) in December 2009 that effectively unwinds the Previous Interest Rate Swaps.

In December 2009, we entered into a new interest rate swap (“New Interest Rate Swap”) to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the 10.375% Senior Unsecured Notes (“Senior Notes”).

The following table sets forth the positions of the Previous, Offsetting and New Interest Rate Swaps for the periods presented:

									Fair Value
	Notional		Swap Interest Rates 1						September 30,			December 31,
Term	Amount		Pay			Receive			2010			2009
Through December 2010	$	50,000		5.349	%	LIBOR			$	(503	)	$	(2,375	)
Through December 2010	$	50,000		LIBOR			0.53	%		30			(39	)
Through June 2013	$	100,000	LIBOR + 8.175		%		10.375	%		3,834			(872	)

1 References to LIBOR represent the 3-month rate.

Financial Statement Impact of Derivatives

The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses on our Condensed Consolidated Statements of Income for the periods presented:

	Location of
	gain (loss)
	recognized	Three Months Ended September 30,					Nine Months Ended September 30,
	in income	2010		2009			2010		2009
Derivatives not designated as
hedging instruments:
Interest rate contracts 1	Interest expense	$	-	$	(2,925	)	$	-	$	(3,864	)
Interest rate contracts	Derivatives		1,732		(420	)		5,677		(597	)
Commodity contracts	Derivatives		13,381		702			38,733		21,080
Total increase (decrease) in
net income resulting from
derivatives		$	15,113	$	(2,643	)	$	44,410	$	16,619
Realized and unrealized derivative
impact:
Cash received for commodity
and interest rate settlements	Derivatives	$	6,803	$	15,821		$	24,287	$	47,801
Cash paid for interest rate
contract settlements	Interest expense		-		-			-		(438	)
Unrealized derivative gain (loss) 2			8,310		(18,464	)		20,123		(30,744	)
Total increase (decrease) in
net income resulting from
derivatives		$	15,113	$	(2,643	)	$	44,410	$	16,619

1 This represents interest rate swap amounts reclassified out of Accumulated other comprehensive income ("AOCI") and into earnings. During 2009, the Company discontinued hedge accounting for the Previous Interest Rate Swaps. A total of $2.9 million and $3.9 million for remaining AOCI and actual hedge settlements for the three and nine months ended September 30, 2009 were reclassified into earnings in the same period or periods relating to the Previous Interest Rate Swaps not designated for hedge accounting.

2 Represents unrealized gains (losses) in the Interest expense and Derivatives caption on our Condensed Consolidated Statements of Income.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our Condensed Consolidated Balance Sheets for the periods presented:

		Fair Values as of
		September 30, 2010				December 31, 2009
		Derivative		Derivative		Derivative		Derivative
Type	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

Interest rate contracts	Derivative assets/liabilities - current	$	2,153	$	503	$	1,463	$	2,413
Commodity contracts	Derivative assets/liabilities - current		22,174		-		14,778		2,483
			24,327		503		16,241		4,896

Interest rate contracts	Derivative assets/liabilities - noncurrent		1,712		-		-		2,334
Commodity contracts	Derivative assets/liabilities - noncurrent		5,819		-		2,346		126
			7,531		-		2,346		2,460
		$	31,858	$	503	$	18,587	$	7,356

At September 30, 2010, we reported a net derivative asset of approximately $28 million related to oil and gas production. The contracts underlying such commodity derivative asset are with five counterparties, all of which are investment grade financial institutions, and such commodity derivative assets are substantially concentrated with two of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, to the extent that this counterparty is affected by changes in economic or other conditions. We have not paid or received collateral with respect to our derivative positions. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts, or approximately $28 million, as of September 30, 2010. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

The effects of derivative gains (losses) and cash settlements of our oil and gas commodity derivatives are reported as adjustments to reconcile net income to net cash provided by operating activities on our Condensed Consolidated Statements of Cash Flows. These items are recorded in the “Total derivative gains” and “Cash receipts to settle derivatives” caption on our Condensed Consolidated Statements of Cash Flows.

As of September 30, 2010, we had not actively traded derivative financial instruments. In addition, as of September 30, 2010, we were not party to any derivative financial instruments containing credit risk contingencies.

6. Property and Equipment, net

The following table summarizes our property and equipment for the periods presented:

	As of
	September 30,			December 31,
	2010			2009
Oil and gas properties:
Proved	$	2,057,901		$	1,887,073
Unproved		166,565			73,067
Total oil and gas properties		2,224,466			1,960,140
Other property and equipment		16,389			15,903
Total property and equipment		2,240,855			1,976,043
Accumulated depreciation, depletion and amortization		(583,172	)		(496,591	)
	$	1,657,683		$	1,479,452

7. Long-Term Debt

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

	As of
	September 30,		December 31,
	2010		2009
Revolving credit facility	$	-	$	-
Senior notes, net of discount (principal amount of $300,000)		292,369		291,749
Convertible notes, net of discount (principal amount of $230,000)		212,155		206,678
	$	504,524	$	498,427

Revolving Credit Facility

The Revolver provides for a $300 million revolving credit facility and matures in November 2012. We have the option to increase the commitments under the Revolver by up to an additional $225 million upon the receipt of commitments from one or more lenders. The Revolver is governed by a borrowing base calculation and the availability under the Revolver may not exceed the lesser of the aggregate commitments or the borrowing base. As of September 30, 2010, the borrowing base, which is redetermined semi-annually, was $420 million.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from LIBOR, as adjusted for statutory reserve requirements for Eurocurrency liabilities (the “Adjusted LIBOR”), plus an applicable margin ranging from 2.000% to 3.000% or (ii) the greater of (a) the prime rate, (b) federal funds effective rate plus 0.5% and (c) the one-month Adjusted LIBOR plus 1.0%, in each case, plus an applicable margin (ranging from 1.000% to 2.000%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity.

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

As of September 30, 2010, there were no amounts outstanding under the Revolver, and we had remaining borrowing capacity of up to $299.3 million, net of outstanding letters of credit of $0.7 million. In addition, there have been no amounts outstanding through the nine months ended September 30, 2010. As of September 30, 2010 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with the applicable covenants of the Revolver.

Senior Notes

The Senior Notes, which mature in June 2016, were originally sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

As of September 30, 2010, approximately 98% of our consolidated assets were held by the Guarantor Subsidiaries with the remainder being held by our parent company, which is the issuer of the Senior Notes. The parent company incurs operating expenses in connection with the administration of its investment in its operating subsidiaries and incurs interest expense and related borrowing costs attributable to the Senior Notes and the 4.5% Convertible Notes (“Convertible Notes”). Accordingly, the parent company has no independent operations. There are no significant restrictions on the ability of the parent company or any of the Guarantor Subsidiaries to obtain funds through dividends or other means, including advances and intercompany notes among others. As a result of the sale of the PVG Common Units, the remaining unrestricted subsidiaries no longer have any assets other than net intercompany accounts receivable with the parent company resulting primarily from the transfer of proceeds received from the sale.

Convertible Notes

The Convertible Notes, which mature in November 2012, are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment.

The Convertible Notes are represented by a liability component which is reported herein as long-term debt, net of discount, and an equity component representing the convertible feature which is included in additional paid-in capital in shareholders’ equity. The following table summarizes the carrying amount of these components for the periods presented:

	As of
	September 30,			December 31,
	2010			2009
Principal	$	230,000		$	230,000
Unamortized discount		(17,845	)		(23,322	)
Net carrying amount of liability component	$	212,155		$	206,678

Carrying amount of equity component	$	36,850		$	36,850

The unamortized discount will be amortized through the end of 2012. The effective interest rate on the liability component of the Convertible Notes for the three and nine months ended September 30, 2010 and 2009 was 8.5%. During each of the three and nine month periods, we recognized $2.6 million and $7.8 million of interest expense, respectively, related to the contractual coupon rate on the Convertible Notes. In addition, we recognized $1.9 million and $1.7 million and $5.5 million and $5.0 million of interest expense related to the amortization of the discount for the three and nine months ended September 30, 2010 and 2009, respectively.

The Convertible Notes are unsecured senior subordinated obligations, ranking junior in right of payment to any of our senior indebtedness and to any of our secured indebtedness to the extent of the value of the assets securing such indebtedness and equal in right of payment to any of our future unsecured senior subordinated indebtedness. The Convertible Notes will rank senior in right of payment to any of our future junior subordinated indebtedness and will structurally rank junior to all existing and future indebtedness of our guarantor subsidiaries.

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

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

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

8. Additional Balance Sheet Detail

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

	As of
	September 30,		December 31,
	2010		2009
Other current assets:
Tubular inventory and well materials	$	5,993	$	10,372
Prepaid expenses		585		1,540
Deferred income taxes		-		1,298
Income tax receivable		-		2,227
	$	6,578	$	15,437

	As of
	September 30,		December 31,
	2010		2009
Other assets:
Debt issuance costs	$	15,183	$	18,175
Long-term investments - SERP		6,136		5,904
Other		50		45
	$	21,369	$	24,124

	As of
	September 30,		December 31,
	2010		2009
Accounts payable and accrued liabilities:
Trade accounts payable	$	31,283	$	26,269
Drilling costs		24,532		11,203
Royalties		7,503		6,397
Production and franchise taxes		8,728		8,209
Compensation		5,202		8,311
Interest		13,346		2,771
Gas imbalance		1,199		1,094
Deposit received on properties sold		-		2,280
Other		3,467		4,190
	$	95,260	$	70,724

	As of
	September 30,		December 31,
	2010		2009
Other liabilities:
Asset retirement obligation	$	7,187	$	6,835
Pension		1,838		1,762
Postretirement health care		3,530		3,452
Deferred compensation		6,628		8,662
Other		900		-
	$	20,083	$	20,711

9. Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2009.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. As of September 30, 2010, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value. The fair value of our fixed-rate, long-term debt is estimated based on the published market prices for the same or similar issues and is provided as follows:

	As of
	September 30,		December 31,
	2010		2009
10.375% Senior Unsecured Notes	$	327,750	$	327,000
4.5% Convertible Notes		224,710		218,742
	$	552,460	$	545,742

Recurring Fair Value Measurements

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

	As of September 30, 2010
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Publicly traded equity securities	$	6,136		$	6,136		$	-		$	-
Interest rate swap assets - current		2,153			-			2,153			-
Interest rate swap assets - noncurrent		1,712			-			1,712			-
Commodity derivative assets - current		22,174			-			22,174			-
Commodity derivative assets - noncurrent		5,819			-			5,819			-

Liabilities:
Deferred compensation - noncurrent liability		(6,624	)		(6,624	)		-			-
Interest rate swap liabilities - current		(503	)		-			(503	)		-
Totals	$	30,867		$	(488	)	$	31,355		$	-

	As of December 31, 2009
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Publicly traded equity securities	$	5,904		$	5,904		$	-		$	-
Interest rate swap assets - current		1,463			-			1,463			-
Commodity derivative assets - current		14,778			-			14,778			-
Commodity derivative assets - noncurrent		2,346			-			2,346			-

Liabilities:
Deferred compensation - noncurrent liability		(6,564	)		(6,564	)		-			-
Interest rate swap liabilities - current		(2,413	)		-			(2,413	)		-
Interest rate swap liabilities - noncurrent		(2,334	)		-			(2,334	)		-
Commodity derivative liabilities - current		(2,483	)		-			(2,483	)		-
Commodity derivative liabilities - noncurrent		(126	)		-			(126	)		-
Totals	$	10,571		$	(660	)	$	11,231		$	-

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

•

Publicly traded equity securities: Our publicly traded equity securities consist of various publicly traded equities that are held as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.

•

Commodity derivatives: We determine the fair values of our oil and gas derivative agreements based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the end of the reporting periods. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. Each of these is a level 2 input.

•

Interest rate swaps: We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a level 2 input.

•

Deferred compensation: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain publicly traded equity securities. The fair values of these obligations are based on quoted market prices, which are level 1 inputs.

In addition to the items provided above, there are other assets and liabilities recorded at fair value on a non-recurring basis. The most significant of these includes the fair value of properties held for sale, consisting of the underlying properties and related assets and liabilities. Their fair value was derived using a market approach based on agreements of sale, adjusted for working capital and closing costs. Because these significant fair value inputs are typically not observable, we have categorized the amounts as level 3 inputs.

10. Shareholders’ Equity and Comprehensive Income

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

	Penn Virginia			Noncontrolling
	Corporation			Interests in			Total
	Shareholders'			Discontinued			Shareholders'			Comprehensive
	Equity			Operations			Equity			Income (Loss)
Balance at December 31, 2009	$	908,088		$	329,911		$	1,237,999
Dividends paid ($0.16875 per share)		(7,700	)		-			(7,700	)
Distributions to noncontrolling interest holders		-			(49,566	)		(49,566	)
Sale of PVG units, net of tax		82,102			70,188			152,290
Deconsolidation of PVG		-			(382,324	)		(382,324	)
Other changes to shareholders' equity		6,061			3,119			9,180
Comprehensive income:
Net income		14,514			28,090			42,604		$	42,604
Hedging reclassification adjustment		-			582			582			582
Other, net of tax		(174	)		-			(174	)		(174	)
Balance at September 30, 2010	$	1,002,891		$	-		$	1,002,891		$	43,012

Balance at December 31, 2008	$	925,215		$	297,227		$	1,222,442
Dividends paid ($0.16875 per share)		(7,278	)		-			(7,278	)
Distributions to noncontrolling interest holders		-			(55,365	)		(55,365	)
Common stock offering		64,835			-			64,835
Sale of PVG units, net of tax		32,739			67,713			100,452
Other changes to shareholders' equity		6,690			2,416			9,106
Comprehensive income:
Net income (loss)		(109,292	)		20,512			(88,780	)	$	(88,780	)
Hedging unrealized loss, net of tax		291			(353	)		(62	)		(62	)
Hedging reclassification adjustment, net of tax		2,293			1,081			3,374			3,374
Balance at September 30, 2009	$	915,493		$	333,231		$	1,248,724		$	(85,468	)

The following table discloses the net income attributable to Penn Virginia and transfers to noncontrolling interests for the nine months ended September 30, 2010:

Net income attributable to Penn Virginia	$	14,514
Transfer to noncontrolling interests:
Increase in Penn Virginia's paid-in capital for sale of PVG units, net of taxes of $46,835		82,102
Changes from net income attributable to Penn Virginia and transfers to noncontrolling interests	$	96,616

11. Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position or results of operations. During the nine months ended September 30, 2010, we established a $0.9 million reserve for a litigation matter.

Significant Customers

For the nine months ended September 30, 2010, four customers accounted for $105.2 million, or approximately 56%, of our total consolidated product revenues. As of September 30, 2010, $26.7 million, or approximately 46% of our consolidated accounts receivable, including joint interest billings, related to these customers.

12.	Share-Based Compensation

Our stock compensation plans permit the grant of incentive and nonqualified stock options, common stock, deferred common stock units, restricted stock and restricted stock units to our employees and directors. Generally, stock options vest over a three-year period, with one-third vesting in each year. Common stock and deferred common stock units granted under our stock compensation plans are vested immediately, and we recognize compensation expense related to those grants on the grant date. Restricted stock and restricted stock units granted under our stock compensation plans vest over a three-year period, with one-third vesting in each year. We recognize compensation expense related to our stock compensation plans in the General and administrative expenses caption on our Condensed Consolidated Statements of Income. The following table summarizes the share-based compensation expense for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Stock option plans	$	1,319	$	1,746	$	4,704	$	5,329
Common, deferred, restricted and restricted unit plans		392		744		1,696		2,116
	$	1,711	$	2,490	$	6,400	$	7,445

13.	Restructuring Activities

In November 2009, we implemented an organization restructuring that resulted in the transfer of certain corporate administrative and oil and gas accounting functions from our Kingsport, Tennessee office location to our Houston, Texas and Radnor, Pennsylvania locations. In addition, the restructuring resulted in the relocation of our eastern region oil and gas divisional office from Kingsport to Pittsburgh, Pennsylvania. Approximately 30 employees were terminated in connection with the restructuring. We incurred special termination benefit costs of approximately $1.4 million, including $0.5 million in 2009 and $0.9 million in 2010, that were paid to eligible employees upon the completion of various transition activities. These costs were charged to operations ratably over the transition period which concluded during the second quarter of 2010. We also incurred relocation costs and other incremental costs associated with staffing and expanding our other office locations including the new office in Pittsburgh.

In connection with these restructuring activities, we also ceased operations at our Kingsport, Tennessee office location during the second quarter of 2010 and assigned the underlying lease of the facility to PVR. In connection with this assignment, we incurred a one-time lease assignment charge, which was paid in July 2010. These restructuring charges, including those described above, are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Income and are comprised of the following for the nine months ended September 30, 2010:

Termination benefits	$	867
Employee and office relocation costs		1,202
Other incremental costs		865
Lease assignment charge		3,500
	$	6,434

The following table summarizes the termination benefit obligations as of and for the nine months ended September 30, 2010:

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

14.	Impairments

We review oil and gas properties and other assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reserve estimates or lower commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amounts of the properties to determine if the carrying amounts are recoverable. The factors used to determine fair value include, but are not limited to, estimates of proved and probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties and other assets. Because these significant fair value inputs are typically not observable, we classify impairments of oil and gas properties and other assets as a level 3 fair value measure.

The impairment charge incurred during the 2010 period is attributable primarily to market declines in spot and future oil and gas prices primarily with respect to certain coal bed methane properties in the Mid-Continent region. In addition, we recorded impairment charges in the third quarter of 2010 attributable to certain oil and gas inventory assets triggered primarily by declines in asset quality. The impairment charges incurred during the 2009 periods include those attributable to our former Gulf Coast properties that were initially classified as held for sale during the third quarter of 2009, as well as certain other oil and gas inventory assets and properties whose impairment was triggered by market declines in spot and future oil and gas prices.

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Oil and gas properties - held for sale	$	-	$	87,900	$	-	$	87,900
Oil and gas properties		32,627		3,649		33,751		4,845
Other - tubular inventory and well materials		2,500		804		2,500		4,083
	$	35,127	$	92,353	$	36,251	$	96,828

15.	Interest Expense

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Interest on borrowings and related fees	$	10,758		$	11,102		$	32,245		$	22,821
Accretion of original issue discount		1,986			2,036			6,097			5,462
Amortization of debt issuance costs		883			782			2,992			1,751
Interest rate swaps		-			2,925			-			3,864
Capitalized interest		(438	)		(566	)		(1,155	)		(1,471	)
Other		9			-			11			(581	)
	$	13,198		$	16,279		$	40,190		$	31,846

16.	Earnings per Share

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net loss from continuing operations	$	(30,159	)	$	(84,712	)	$	(40,490	)	$	(121,561	)
Income from discontinued operations, net of tax 1		-			15,321			33,482			32,781
Gain on sale of discontinued operations, net of tax		-			-			49,612			-
Less net income attributable to noncontrolling interests		-			(10,509	)		(28,090	)		(20,512	)
Net income (loss) attributable to common shareholders	$	(30,159	)	$	(79,900	)	$	14,514		$	(109,292	)
Less: Portion of subsidiary net income
allocated to undistributed share-based
compensation awards, net of taxes		-			(34	)		(28	)		(68	)
	$	(30,159	)	$	(79,934	)	$	14,486		$	(109,360	)

Weighted-average shares, basic		45,591			45,427			45,534			43,324
Effect of dilutive securities 2		-			-			199			-
Weighted-average shares, diluted		45,591			45,427			45,733			43,324

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

2 For the three months ended September 30, 2010 and 2009, and the nine months ended September 30, 2009, approximately 0.1 million potentially dilutive securities, including the Convertible Notes, stock options, restricted stock and restricted stock units, had the effect of being anti-dilutive and were excluded from the calculation of diluted earnings per common share.

17.	New Accounting Standards

In January 2010, the Financial Accounting Standards Board issued guidance on increased fair-value measurement disclosures. The guidance requires us to make new disclosures about recurring or nonrecurring fair-value measurements, including significant transfers into and out of level 1 and level 2 fair-value measurements and information on purchases, sales, issuances and settlements on a gross basis in the reconciliation of level 3 fair-value measurements. The guidance also clarified existing fair-value measurement disclosure about the level of disaggregation, inputs and valuation techniques. Except for the detail level 3 roll forward disclosures, this guidance is effective for annual and interim reporting beginning in the first quarter of 2010. The new disclosures about purchases, sales, issuances and settlements in the roll forward activity for level 3 fair-value measurements are effective for interim and annual reporting beginning in the first quarter of 2011. The Company adopted the provisions of the guidance during the first quarter of 2010 with no significant impact on its fair-value measurement disclosures. In addition, the Company does not anticipate any significant impact from the required level 3 roll-forward disclosures effective in 2011.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

•

the volatility of commodity prices for natural gas, natural gas liquids, or NGLs, and crude oil;

•

our ability to access external sources of capital;

•

uncertainties relating to the occurrence and success of capital-raising transactions, including securities offerings and asset sales;

•

reductions in the borrowing base under the 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 and crude oil;

•

the projected demand for and supply of natural gas, NGLs and crude oil;

•

the availability and costs of required drilling rigs, production equipment and materials;

•

our ability to obtain adequate pipeline transportation capacity for our oil and gas production;

•

competition among producers in the oil and natural gas industry generally;

•

the extent to which the amount and quality of actual production of our oil and natural gas differ from estimated proved oil and gas reserves;

•

operating risks, including unanticipated geological problems, incidental to our business;

•

the occurrence of unusual weather or operating conditions including force majeure events;

•

delays in anticipated start-up dates of our oil and natural gas production;

•

environmental risks affecting the drilling and producing of oil and gas wells;

•

the timing of receipt of necessary governmental permits by us;

•

hedging results;

•

accidents;

•

changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters;

•

risks and uncertainties relating to general domestic and international economic (including inflation, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and

•

other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2009.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Corporation and its subsidiaries (“Penn Virginia,” the “Company,” “we,” “us” or “our”) should be read in conjunction with our Condensed Consolidated Financial Statements and Notes thereto included in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are an independent oil and gas company engaged primarily in the development, exploration and production of natural gas and oil in various domestic onshore regions. We have a geographically diverse asset base with core areas of operations in the Mid-Continent, East Texas, Appalachia and Mississippi regions of the United States. As of June 30, 2010, we had proved natural gas and oil reserves of approximately 967 Bcfe. Our operations include both conventional and unconventional development drilling opportunities, as well as some exploratory prospects.

The divestiture of our holdings in Penn Virginia GP Holdings, L.P., or PVG, completed the process of our transformation into a “pure play” exploration and production (E&P) company. We believe our emerging presence in several key plays as discussed below positions us for meaningful growth over the next several years.

The primary development play types that we are currently focused on include: (i) the horizontal Granite Wash play in Mid-Continent and (ii) the horizontal Lower Bossier (Haynesville) Shale play in East Texas. We also plan to expand development opportunities with our recent acquisition of properties in the Eagle Ford Shale play in South Texas, and we intend to focus on drilling exploratory wells in the Marcellus Shale play in Appalachia in order to determine whether our leasehold acreage position there will support a development program.

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Total production (MMcfe)		13,280			12,410			34,093			39,672
Daily production (MMcfe per day)		144.3			134.9			124.9			145.3

Realized prices per Mcfe, as reported	$	5.15		$	4.25		$	5.50		$	4.32
Realized prices per Mcfe, adjusted for derivatives	$	5.70		$	5.58		$	6.24		$	5.55

Product revenues, as reported	$	68,331		$	52,760		$	187,387		$	171,270
Product revenues, as adjusted for derivatives	$	75,763		$	69,186		$	212,644		$	220,192

Operating loss	$	(53,053	)	$	(122,069	)	$	(73,839	)	$	(188,851	)
Interest expense	$	13,198		$	16,279		$	40,190		$	31,846

Cash provided by operating activities	$	23,206		$	41,751		$	68,875		$	107,193
Cash paid for capital expenditures	$	145,629		$	18,260		$	313,710		$	183,528

Cash and cash equivalents at end of period							$	204,452		$	83,840
Debt outstanding, net of discounts, at end of period							$	504,524		$	496,367
Credit available under Revolver at end of period							$	299,268		$	366,268

Net development wells drilled		11.7			0.8			32.5			17.4
Net exploratory wells drilled		1.2			-			2.2			1.0

Key Developments

During the nine months ended September 30, 2010, the following general business developments and corporate actions had an impact on the financial reporting of our results of operations and financial position: (i) the complete divestiture of our interests in PVG, (ii) the acquisition of properties in the Eagle Ford and Marcellus Shale plays, (iii) the signing of a fracturing services agreement for well completion activities, (iv) the completion of our organization restructuring that was announced in the fourth quarter of 2009 and (v) the completion of the disposition of our Gulf Coast properties. A discussion of these key developments follows:

Divestiture and Deconsolidation of PVG

Prior to June 2010, we indirectly owned partner interests in Penn Virginia Resource Partners, L.P., or PVR, which is engaged in the coal and natural resource management and natural gas midstream businesses. Our ownership interests in PVR were held primarily through our general and limited partner interests in PVG. In June 2010, we completed the sale of our remaining limited partner interests in PVG in a secondary public offering for proceeds of approximately $139 million, net of offering costs. In a related transaction, we disposed of 100% of the membership interest in PVG’s general partner, thereby relinquishing control of PVG. As a result of these transactions, we recognized a gain of $49.6 million, net of taxes, during the three months ended June 30, 2010 and have deconsolidated PVG from our Condensed Consolidated Financial Statements. The results of operations attributable to PVG through the date of these transactions and prior periods have been presented as discontinued operations in our Condensed Consolidated Financial Statements. Since September 2009, we sold approximately 30.1 million common units representing 77% of the ownership of PVG and raised approximately $450 million in net pre-tax proceeds. Additional information is provided in the Liquidity and Capital Resources discussion that follows.

Property Acquisitions

In August 2010, we acquired approximately 6,800 net acres in the Eagle Ford Shale play in Texas for approximately $31.1 million. The acreage includes over 40 horizontal well locations. We are the operator with a working interest of approximately 75% and a net revenue interest of approximately 57%. In May 2010, we acquired approximately 10,000 net acres in the Marcellus Shale play in Pennsylvania in two transactions for approximately $19.5 million. The first transaction included approximately 7,900 net acres with Marcellus Shale rights and approximately 23,000 net acres with deeper rights. In connection with this acquisition, we granted the seller a 1.5 percent overriding royalty interest on the acquired acreage. The second transaction included approximately 2,100 net acres with rights to the Marcellus Shale and all other formations.

Fracturing Services Agreement

In May 2010, we entered into a one-year agreement with C&J Energy Services, Inc. to provide hydraulic fracturing services in our East Texas and Mid-Continent regions. The supply of such services and related equipment had been constrained in those regions and led to the delays in well completions that we experienced during the first half of the year. As a result of the agreement, we have secured access to equipment and services necessary to complete the backlog of wells drilled, together with wells to be drilled during the remainder of 2010 and the first half of 2011. The agreement was recently amended to provide for equipment and services into the South Texas region in support of our expansion into the Eagle Ford Shale play.

Organization Restructuring

In November 2009, we implemented an organization restructuring that resulted in the transfer of certain corporate and oil and gas accounting and administrative functions from our Kingsport, Tennessee office location to our Houston, Texas and Radnor, Pennsylvania locations. In addition, the restructuring resulted in the relocation of our eastern region oil and gas divisional office from Kingsport to Pittsburgh, Pennsylvania. Approximately 30 employees were terminated in connection with the restructuring, which was substantially completed during the second quarter of 2010. In 2010, we have incurred $2.9 million in costs including termination benefits, relocation costs and other incremental costs associated with expanding our other office locations. In addition, we incurred a lease assignment charge of $3.5 million in connection with the assignment of a lease for our former Kingsport, Tennessee office facility to PVR.

Disposition of Gulf Coast Properties

In January 2010, we completed the sale of our Gulf Coast properties in exchange for cash proceeds of $23.2 million, net of transaction costs and purchase and sale adjustments, plus the receipt of certain oil and gas properties in the Selma Chalk play in our Mississippi region.

Results of Operations

Three Months Ended September 30, 2010 Compared With Three Months Ended September 30, 2009

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

	Three Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		10,890			10,634			256			2	%
Crude oil (MBbl)		189			202			(13	)		(7	)%
NGL (MBbl)		210			94			116			123	%
Total production (MMcfe)		13,280			12,410			870			7	%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.36		$	3.45		$	0.91			26	%
Crude oil ($/Bbl)		70.97			65.64			5.33			8	%
NGL ($/Bbl)		35.57			30.29			5.29			17	%
Total ($/Mcfe)	$	5.15		$	4.25		$	0.89			21	%

Revenues
Natural gas	$	47,476		$	36,654		$	10,822			30	%
Crude oil		13,396			13,259			137			1	%
NGL		7,459			2,847			4,612			162	%
Total product revenues		68,331			52,760			15,571			30	%
Gain on sale of property and equipment		280			1,945			(1,665	)		(86	)%
Other income		342			1,014			(672	)		(66	)%
Total revenues		68,953			55,719			13,234			24	%

Operating Expenses
Lease operating		9,256			10,787			1,531			14	%
Gathering, processing and transportation		3,625			2,424			(1,201	)		(50	)%
Production and ad valorem taxes		5,309			3,842			(1,467	)		(38	)%
General and administrative		13,445			11,946			(1,499	)		(13	)%
Exploration		22,020			16,117			(5,903	)		(37	)%
Depreciation, depletion and amortization		33,224			40,319			7,095			18	%
Impairments		35,127			92,353			57,226			62	%
Total operating expenses		122,006			177,788			55,782			31	%

Operating loss		(53,053	)		(122,069	)		69,016			57	%
Other income (expense)
Interest expense		(13,198	)		(16,279	)		3,081			19	%
Derivatives		15,113			281			14,832			5278	%
Other		342			4			338			8450	%
Income tax benefit		20,637			53,351			(32,714	)		(61	)%
Income from discontinued operations, net of tax		-			15,321			(15,321	)		n/a
Net loss		(30,159	)		(69,391	)		39,232			57	%
Less:
Net income attributable to noncontrolling interests		-			(10,509	)		10,509			n/a
Net loss attributable to Penn Virginia Corporation	$	(30,159	)	$	(79,900	)	$	49,741			62	%

Production

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

	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2010		2009		(Unfavorable)			2010		2009		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
East Texas		4,024		3,034		990			43.7		33.0		10.8			33	%
Appalachia		2,704		2,882		(178	)		29.4		31.3		(1.9	)		(6	)%
Mid-Continent		4,474		3,372		1,102			48.6		36.7		12.0			33	%
Mississippi		2,078		1,875		203			22.6		20.4		2.2			11	%
Gulf Coast		-		1,247		(1,247	)		-		13.6		(13.6	)		n/a
Total production		13,280		12,410		870			144.3		134.9		9.5			7	%

Approximately 82% and 86% of total production in the three months ended September 30, 2010 and 2009 was natural gas. The change reflects our current focus on liquids-rich regions in the Mid-Continent and East Texas. The increase in total volume is due primarily to production from new wells in the Granite Wash play in the Mid-Continent region that were brought online during the first nine months of 2010. The overall increase was partially offset by the loss of production resulting from the disposition of our Gulf Coast properties in January 2010.

Product Revenues and Prices

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

	Three Months Ended							Three Months Ended
	September 30,				Favorable			September 30,				Favorable
	2010		2009		(Unfavorable)			2010		2009		(Unfavorable)
								($ per Mcfe)
East Texas	$	18,718	$	11,399	$	7,319		$	4.65	$	3.76	$	0.89
Appalachia		11,796		10,136		1,660			4.36		3.52		0.85
Mid-Continent		28,244		18,493		9,751			6.31		5.48		0.82
Mississippi		9,573		6,769		2,804			4.61		3.61		1.00
Gulf Coast		-		5,963		(5,963	)		-		4.78		n/a
Total revenues	$	68,331	$	52,760	$	15,571		$	5.15	$	4.25	$	0.89

As illustrated below, improved pricing in all three commodity product types contributed significantly to the overall increase in revenues despite a modest decline in oil volumes over the prior year period. The following table provides an analysis of the change in our revenues for the three months ended September 30, 2010 as compared to the three months ended September 30, 2009:

	Revenue Variance Due to
	Volume			Price		Total
Natural gas	$	881		$	9,941	$	10,822
Crude oil		(869	)		1,006		137
NGL		3,503			1,109		4,612
	$	3,515		$	12,056	$	15,571

Effects of Derivatives

Our revenues may vary significantly from period to period as a result of fluctuations in commodity prices or production volumes. As part of our risk management strategy, we use derivative financial instruments to hedge natural gas and, to a lesser extent, oil prices. We received $7.4 million and $16.4 million in cash settlements for commodity derivatives in the three months ended September 30, 2010 and 2009, respectively.

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

	Three Months Ended September 30,					Favorable
	2010			2009		(Unfavorable)			% Change
Natural gas revenues as reported	$	47,476		$	36,654	$	10,822			30	%
Cash settlements on natural gas derivatives		7,497			15,466		(7,969	)		(52	)%
Natural gas revenues adjusted for derivatives	$	54,973		$	52,120	$	2,853			5	%

Natural gas prices per Mcf, as reported	$	4.36		$	3.45	$	0.91			26	%
Cash settlements on natural gas derivatives per Mcf		0.69			1.45		(0.77	)		(53	)%
Natural gas prices per Mcf adjusted for derivatives	$	5.05		$	4.90	$	0.14			4	%

Crude oil revenues as reported	$	13,396		$	13,259	$	137			1	%
Cash settlements on crude oil derivatives		(65	)		960		(1,025	)		(107	)%
Crude oil revenues adjusted for derivatives	$	13,331		$	14,219	$	(888	)		(6	)%

Crude oil prices per Bbl, as reported	$	70.97		$	65.64	$	5.33			8	%
Cash settlements on crude oil derivatives per Bbl		(0.35	)		4.75		(5.10	)		(107	)%
Crude oil prices per Bbl adjusted for derivatives	$	70.62		$	70.39	$	0.23		<1		%

Operating Expenses

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

	Three Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Lease operating	$	0.70	$	0.87	$	0.17			20	%
Gathering, processing and transportation		0.27		0.20		(0.08	)		(40	)%
Production and ad valorem taxes		0.40		0.31		(0.09	)		(29	)%
General and administrative		1.01		0.96		(0.05	)		(5	)%
General and administrative excluding share-based
compensation and restructuring charges		0.82		0.76		(0.06	)		(8	)%
Depreciation, depletion and amortization		2.50		3.25		0.75			23	%

Lease Operating

The 2010 period reflects lower charges for equipment and compressor rentals, water disposal and contract labor, partially offset by higher repairs and maintenance costs. Decreases in certain of these costs reflect our exit from the Gulf Coast region when compared to the prior year period.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during the 2010 period primarily as a result of the production increase and a change in the geographic distribution of production from the Gulf Coast to the Mid-Continent region. In addition, we are incurring higher processing costs associated with NGLs from our Granite Wash operated and non-operated wells in the Mid-Continent region.

Production and Ad Valorem Taxes

Production and ad valorem taxes increased as a result of higher production and related revenues. As a percentage of revenue, the combined tax rate increased to 7.8% during the 2010 period from 7.3% during the 2009 period.

General and Administrative

General and administrative expenses increased due primarily to restructuring charges attributable to employee and office relocation costs associated with the organization restructuring announced during November 2009. Actual restructuring charges incurred during the 2010 period were $0.8 million. In addition, we incurred higher consulting and professional fees, offset partially by lower share-based compensation expense.

Exploration

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

	Three Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Dry hole costs	$	9,032	$	52	$	(8,980	)		(17269	)%
Geological and geophysical		4,088		116		(3,972	)		(3424	)%
Unproved leasehold		7,951		10,257		2,306			22	%
Rig standby charges		-		3,713		3,713			n/a
Other, primarily delay rentals		949		1,979		1,030			52	%
	$	22,020	$	16,117	$	(5,903	)		(37	)%

During the third quarter of 2010 we incurred dry hole costs attributable to an exploratory well in the Mountain View prospect in the Mid-Continent region. Higher geological and geophysical costs incurred during the 2010 period represent seismic studies conducted in connection with our more aggressive drilling program in the current year. The amortization of unproved leasehold property was higher during the prior year period due to a change in accounting estimate in 2009 to collectively amortize insignificant unproved properties over the average estimated useful life of the leases. Rig standby charges were incurred during the 2009 period as a result of the reduction in our 2009 drilling program.

Depreciation, Depletion and Amortization (DD&A)

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

	Three Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)		% Change
Depreciation - Oil and gas operations	$	621	$	680	$	59		9	%
Depreciation - Corporate		659		993		334		34	%
Depletion		31,833		38,521		6,688		17	%
Amortization		111		125		14		11	%
	$	33,224	$	40,319	$	7,095		18	%

	DD&A Variance Due to
	Production			Rates		Total
Three months ended September 30, 2010 compared to 2009	$	(2,827	)	$	9,922	$	7,095

Our average depletion rate decreased to $2.40 per Mcfe for the 2010 period from $3.10 per Mcfe during the 2009 period. The decrease was the result of discoveries in the Mid-Continent region and an impairment of certain coal bed methane properties.

Impairments

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

	Three Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Oil and gas properties - held for sale	$	-	$	87,900	$	87,900			n/a
Oil and gas properties		32,627		3,649		(28,978	)		(794	)%
Other - tubular inventory and well materials		2,500		804		(1,696	)		(211	)%
	$	35,127	$	92,353	$	57,226			62	%

During the three months ended September 30, 2010, we incurred impairment charges with respect to certain coal bed methane properties in the Mid-Continent region due to market declines in spot and future oil and gas prices. In addition, we recorded impairment charges attributable to certain oil and gas inventory assets triggered primarily by declines in asset quality. During the three months ended September 30, 2009, we incurred impairment charges in connection with the initial classification of the Gulf Coast properties as assets held for sale as well as impairments attributable to tubular inventory and other oil and gas properties.

Interest Expense

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

	Three Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Interest on borrowings and related fees	$	10,758		$	11,102		$	344			3	%
Accretion of original issue discount		1,986			2,036			50			2	%
Amortization of debt issuance costs		883			782			(101	)		(13	)%
Interest rate swaps		-			2,925			2,925			n/a
Capitalized interest		(438	)		(566	)		(128	)		(23	)%
Other, net		9			-			(9	)		n/a
	$	13,198		$	16,279		$	3,081			19	%

Excluding the prior year effect of interest rate swaps, interest expense was relatively comparable. The prior period reclassification of expense from accumulated other comprehensive income, or AOCI, was attributable to the discontinuation of hedge accounting related to our interest rate swaps.

Derivatives

The components of our derivative income are presented below for the periods presented:

	Three Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Oil and gas unrealized derivative gain (loss)	$	5,949		$	(15,725	)	$	21,674			138	%
Oil and gas realized gain		7,433			16,426			(8,993	)		(55	)%
Interest rate swap unrealized gain		2,361			185			2,176			1176	%
Interest rate swap realized gain (loss)		(630	)		(605	)		(25	)		(4	)%
	$	15,113		$	281		$	14,832			5278	%

Cash received for settlements during the three months ended September 30, 2010 was $6.8 million as compared to $15.8 million during the comparable period in 2009.

Other

Other income increased during the three months ended September 30, 2010 due primarily to higher interest income on the significantly larger cash balances held following the disposition of our investment in PVG.

Income Tax Expense

The effective tax rate for the three months ended September 30, 2010 was 40.6% as compared to 38.6% for the comparable period in 2009. Due to operating losses incurred, we recognized an income tax benefit during both periods.

Discontinued Operations

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

	Three Months Ended September 30,					Favorable
	2010		2009			(Unfavorable)			% Change
Revenues	$	-	$	139,444		$	(139,444	)		n/a

Income from discontinued operations before taxes	$	-	$	18,267		$	(18,267	)		n/a
Income tax expense 1		-		(2,946	)		2,946			n/a
Income from discontinued operations, net of taxes	$	-	$	15,321		$	(15,321	)		n/a

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

Nine Months Ended September 30, 2010 Compared With Nine Months Ended September 30, 2009

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

	Nine Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		28,590			33,858			(5,268	)		(16	)%
Crude oil (MBbl)		522			588			(66	)		(11	)%
NGL (MBbl)		395			381			14			4	%
Total production (MMcfe)		34,093			39,672			(5,579	)		(14	)%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.70		$	3.82		$	0.88			23	%
Crude oil ($/Bbl)		72.96			53.42			19.54			37	%
NGL ($/Bbl)		37.96			27.70			10.26			37	%
Total ($/Mcfe)	$	5.50		$	4.32		$	1.18			27	%

Revenues
Natural gas	$	134,283		$	129,305		$	4,978			4	%
Crude oil		38,117			31,412			6,705			21	%
NGL		14,987			10,553			4,434			42	%
Total product revenues		187,387			171,270			16,117			9	%
Gain on sale of property and equipment		616			1,945			(1,329	)		(68	)%
Other income		2,116			2,981			(865	)		(29	)%
Total revenues		190,119			176,196			13,923			8	%
Operating Expenses
Lease operating		27,148			34,208			7,060			21	%
Gathering, processing and transportation		10,165			8,580			(1,585	)		(18	)%
Production and ad valorem taxes		12,684			11,305			(1,379	)		(12	)%
General and administrative		44,297			35,531			(8,766	)		(25	)%
Exploration		37,590			54,901			17,311			32	%
Depreciation, depletion and amortization		95,358			122,095			26,737			22	%
Impairments		36,251			96,828			60,577			63	%
Other		465			1,599			1,134			71	%
Total operating expenses		263,958			365,047			101,089			28	%

Operating loss		(73,839	)		(188,851	)		115,012			61	%
Other income (expense)
Interest expense		(40,190	)		(31,846	)		(8,344	)		(26	)%
Derivatives		44,410			20,483			23,927			117	%
Other		2,105			1,254			851			68	%
Income tax (expense) benefit		27,024			77,399			(50,375	)		(65	)%
Income from discontinued operations, net of tax		33,482			32,781			701			2	%
Gain on sale of discontinued operations, net of tax		49,612			-			49,612			n/a
Net income (loss)		42,604			(88,780	)		131,384			148	%
Less:
Net income attributable to noncontrolling interests		(28,090	)		(20,512	)		(7,578	)		(37	)%
Net income (loss) attributable to Penn Virginia Corporation	$	14,514		$	(109,292	)	$	123,806			113	%

Production

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

	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2010		2009		(Unfavorable)			2010		2009		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
East Texas		9,225		10,429		(1,204	)		33.8		38.2		(4.4	)		(12	)%
Appalachia		7,891		8,715		(824	)		28.9		31.9		(3.0	)		(9	)%
Mid-Continent		11,188		9,684		1,504			41.0		35.5		5.5			16	%
Mississippi		5,494		6,118		(624	)		20.1		22.4		(2.3	)		(10	)%
Gulf Coast		295		4,726		(4,431	)		1.1		17.3		(16.2	)		(94	)%
Total production		34,093		39,672		(5,579	)		124.9		145.3		(20.4	)		(14	)%

The decline in production during the nine months ended September 30, 2010 was due primarily to the disposition of our Gulf Coast properties in January 2010 as well as natural declines in production rates. These natural declines were expected to be replaced with new production; however, we experienced equipment and service-related delays in new well completions during the first half of 2010 primarily in the Lower Bossier (Haynesville) Shale play in the East Texas region and the Granite Wash play in the Mid-Continent region. In order to address this issue, we secured critical fracturing and completion services from a vendor for a one-year period which began in July 2010. This action allowed us to avoid further delays and make substantial progress in completing our backlog of wells in addition to executing our larger drilling program. Accordingly, the results for the quarterly period ended September 30, 2010 reflect this progress which we expect to continue for the remainder of 2010. The overall decline in production volume was partially offset by production from new wells in the Granite Wash play in the Mid-Continent region that were brought online during the first nine months of 2010.

Product Revenues and Prices

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

	Nine Months Ended							Nine Months Ended
	September 30,				Favorable			September 30,				Favorable
	2010		2009		(Unfavorable)			2010		2009		(Unfavorable)
								($ per Mcfe)
East Texas	$	47,125	$	42,211	$	4,914		$	5.11	$	4.05	$	1.06
Appalachia		36,404		35,740		664			4.61		4.10		0.51
Mid-Continent		75,326		44,314		31,012			6.73		4.58		2.16
Mississippi		26,356		25,298		1,058			4.80		4.14		0.66
Gulf Coast		2,176		23,707		(21,531	)		7.38		5.02		2.36
Total revenues	$	187,387	$	171,270	$	16,117		$	5.50	$	4.32	$	1.18

As illustrated below, revenues were higher compared to the prior year period as the decline in production volume discussed above was more than offset by improved pricing for all three commodity product types. The following table provides an analysis of the change in our revenues for the nine months ended September 30, 2010 as compared to the nine months ended September 30, 2009:

	Revenue Variance Due to
	Volume			Price		Total
Natural gas	$	(20,120	)	$	25,098	$	4,978
Crude oil		(3,503	)		10,208		6,705
NGL		382			4,052		4,434
	$	(23,241	)	$	39,358	$	16,117

Effects of Derivatives

For natural gas and crude oil derivatives, we received $25.3 million and $48.9 million in cash settlements in the nine months ended September 30, 2010 and 2009, respectively. The following table reconciles natural gas and crude oil revenues to realized prices, as adjusted for derivative activities, for the periods presented:

	Nine Months Ended September 30,					Favorable
	2010			2009		(Unfavorable)			% Change
Natural gas revenues as reported	$	134,283		$	129,305	$	4,978			4	%
Cash settlements on natural gas derivatives		25,424			45,232		(19,808	)		(44	)%
Natural gas revenues adjusted for derivatives	$	159,707		$	174,537	$	(14,830	)		(8	)%

Natural gas prices per Mcf, as reported	$	4.70		$	3.82	$	0.88			23	%
Cash settlements on natural gas derivatives per Mcf		0.89			1.33		(0.44	)		(33	)%
Natural gas prices per Mcf adjusted for derivatives	$	5.59		$	5.15	$	0.44			8	%

Crude oil revenues as reported	$	38,117		$	31,412	$	6,705			21	%
Cash settlements on crude oil derivatives		(167	)		3,690		(3,857	)		(105	)%
Crude oil revenues adjusted for derivatives	$	37,950		$	35,102	$	2,848			8	%

Crude oil prices per Bbl, as reported	$	72.96		$	53.42	$	19.54			37	%
Cash settlements on crude oil derivatives per Bbl		(0.32	)		6.28		(6.60	)		(105	)%
Crude oil prices per Bbl adjusted for derivatives	$	72.64		$	59.70	$	12.94			22	%

Operating Expenses

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

	Nine Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Lease operating	$	0.80	$	0.86	$	0.07			8	%
Gathering, processing and transportation		0.30		0.22		(0.08	)		(38	)%
Production and ad valorem taxes		0.37		0.28		(0.09	)		(31	)%
General and administrative		1.30		0.90		(0.40	)		(45	)%
General and administrative excluding share-based
compensation and restructuring charges		0.92		0.71		(0.21	)		(30	)%
Depreciation, depletion and amortization		2.80		3.08		0.28			9	%

Lease Operating

The most significant decline in lease operating expenses resulted from decreases in charges that are generally correlated with production volume including water disposal, compressor and other equipment rentals, contract labor, chemical and treating and repairs and maintenance costs.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during the 2010 period primarily as a result of a settlement with a gathering services provider attributable to disputed charges in several prior periods, as well as a change in the geographic distribution of production from the Gulf Coast to the Mid-Continent region including higher processing costs associated with NGLs in the Mid-Continent region. These items were offset partially by the effect of lower volume in the current period.

Production and Ad Valorem Taxes

Production and ad valorem taxes increased commensurately with higher production and related revenues. As a percentage of revenue, production and ad valorem taxes increased to 6.8% in the 2010 period from 6.6% during the 2009 period.

General and Administrative

Higher general and administrative expenses in the 2010 period include restructuring charges of $2.9 million attributable to termination benefits, office and employee relocation and other costs associated with the organization restructuring announced during November 2009, as well as a $3.5 million charge related to the assignment of our lease of our former Kingsport, Tennessee office facility to PVR. In addition, we incurred higher consulting and professional fees offset partially by lower share-based compensation expense.

Exploration

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

	Nine Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Dry hole costs	$	9,059	$	1,389	$	(7,670	)		(552	)%
Geological and geophysical		8,573		1,195		(7,378	)		(617	)%
Unproved leasehold		17,442		28,803		11,361			39	%
Rig standby charges		-		20,316		20,316			n/a
Other, primarily delay rentals		2,516		3,198		682			21	%
	$	37,590	$	54,901	$	17,311			32	%

The decrease in exploration expense is attributable primarily to rig standby charges incurred during the 2009 period. These charges were a direct result of our 2009 drilling program reduction due to unfavorable economic conditions. In addition, the 2009 period reflects the initial impact of a change in accounting estimate to amortize collectively insignificant unproved properties over the average estimated life of the leases rather than amortizing some leases and assessing other leases individually. The decrease was offset partially by dry hole costs attributable to an exploratory well in the Mountain View prospect in the Mid-Continent region during the third quarter of 2010 and higher geological and geophysical costs attributable to our larger 2010 drilling and exploration program.

Depreciation, Depletion and Amortization (DD&A)

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

	Nine Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)		% Change
Depreciation - Oil and gas operations	$	1,913	$	2,090	$	177		8	%
Depreciation - Corporate		2,736		2,853		117		4	%
Depletion		90,377		116,779		26,402		23	%
Amortization		332		373		41		11	%
	$	95,358	$	122,095	$	26,737		22	%

	DD&A Variance Due to
	Production		Rates			Total
Nine months ended September 30, 2010 compared to 2009	$	28,882	$	(2,145	)	$	26,737

Our average depletion rate decreased to $2.65 per Mcfe for the 2010 period from $2.94 per Mcfe during the 2009 period. The reduction was a result of discoveries and the impact of impairments in the current year.

Impairments

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

	Nine Months Ended September 30,				Favorable
	2010		2009		(Unfavorable)			% Change
Oil and gas properties - held for sale	$	-	$	87,900	$	87,900			n/a
Oil and gas properties		33,751		4,845		(28,906	)		(597	)%
Other - tubular inventory and well materials		2,500		4,083		1,583			39	%
	$	36,251	$	96,828	$	60,577			63	%

During the nine months ended September 30, 2010, we incurred impairment charges related primarily to certain coal bed methane properties in the Mid-Continent region as a result of market declines in gas prices. In addition, we recorded impairment charges attributable to certain oil and gas inventory assets triggered primarily by declines in asset quality. During the nine months ended September 30, 2009, we incurred impairment charges in connection with the initial classification of the Gulf Coast properties as assets held for sale at their fair value less costs to sell. In addition, we incurred impairments attributable to tubular inventory and other oil and gas properties.

Other

During the 2010 period, we recorded a loss of $0.5 million on the disposition of our Gulf Coast properties. The loss reflects final purchase price adjustments associated with the period from the effective date in October 2009 to the closing date in January 2010. The 2009 period reflects a loss on the sales of inventory and an oil and gas property.

Interest Expense

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

	Nine Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Interest on borrowings and related fees	$	32,245		$	22,821		$	(9,424	)		(41	)%
Accretion of original issue discount		6,097			5,462			(635	)		(12	)%
Amortization of debt issuance costs		2,992			1,751			(1,241	)		(71	)%
Interest rate swaps		-			3,864			3,864			n/a
Capitalized interest		(1,155	)		(1,471	)		(316	)		(21	)%
Other, net		11			(581	)		(592	)		(102	)%
	$	40,190		$	31,846		$	(8,344	)		(26	)%

Interest expense increased due to higher interest rates on outstanding borrowings, primarily the 10.375% Senior Unsecured Notes, or Senior Notes issued in June 2009. We realized higher amortization of the original issue discount and issuance costs on the Senior Notes and 4.5% Convertible Notes, or Convertible Notes, as well as higher amortization of issuance costs associated with the revolving credit facility, or Revolver. In addition, the prior year period included a reclassification of expense from AOCI attributable to the discontinuation of hedge accounting related to our interest rate swaps, as well as a reversal of interest cost attributable to the settlement of various state income tax positions.

Derivatives

The components of our derivative income are presented below for the periods presented:

	Nine Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Oil and gas unrealized derivative gain (loss)	$	13,476		$	(27,842	)	$	41,318			148	%
Oil and gas realized gain		25,258			48,922			(23,664	)		(48	)%
Interest rate swap unrealized gain		6,646			524			6,122			1168	%
Interest rate swap realized loss		(970	)		(1,121	)		151			13	%
	$	44,410		$	20,483		$	23,927			117	%

Cash received for settlements during the nine months ended September 30, 2010 was $24.3 million as compared to $47.8 million during the comparable period in 2009.

Other

Other income increased during the nine months ended September 30, 2010 due primarily to the gains on the sale of non-operating investments as well as higher interest income on the significantly larger cash balances held following of the disposition of our investment in PVG.

Income Tax Expense

The effective tax rate for the nine months ended September 30, 2010 was 40.0% as compared to 38.9% for the comparable period in 2009. Due to the operating losses incurred, we recognized an income tax benefit during both periods.

Discontinued Operations

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

	Nine Months Ended September 30,						Favorable
	2010			2009			(Unfavorable)			% Change
Revenues	$	303,206		$	402,044		$	(98,838	)		(25	)%

Income from discontinued operations before taxes	$	36,832		$	40,593		$	(3,761	)		(9	)%
Income tax expense 1		(3,350	)		(7,812	)		4,462			57	%
Income from discontinued operations, net of taxes	$	33,482		$	32,781		$	701			2	%

The disclosures for the 2010 period provided in the table above reflect the results of operations of PVG through the date of the disposition of our entire remaining interest in PVG on June 7, 2010.

Gain on Sale of Discontinued Operations

The following table summarizes the determination of the gain recognized on the disposition of the PVG discontinued operations:

Cash proceeds, net of offering costs (8,827,429 units x $15.76 per unit)	$	139,120
Carrying value of noncontrolling interests in PVG at date of disposition		382,324
				521,444
Less: Carrying value of PVG's assets and liabilities at date of disposition				(436,704	)
				84,740
Less: Income tax expense				(35,128	)
Gain on sale of discontinued operations, net of tax			$	49,612

Noncontrolling Interests

The increase in net income attributable to noncontrolling interests during the nine months ended September 30, 2010 is directly attributable to an increase in PVG’s net income as well as a reduction in our ownership of PVG. During the nine months ended September 30, 2010, our ownership interest in PVG declined from 51.4% to zero as compared to 77.0% throughout the comparable period in 2009.

Liquidity and Capital Resources

Cash Flows

Since the third quarter of 2009, our cash needs have been met with a combination of operating cash flows and asset sales. Our cash needs will continue to be met with a combination of these sources, Revolver borrowings and supplemental issues of debt and equity as necessary. We satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, asset sales and borrowings under the Revolver as necessary. We believe that cash on hand and cash generated from our operations and our borrowing capacity will be sufficient to meet our 2010 working capital requirements, anticipated capital expenditures (other than acquisitions), scheduled debt payments and dividend payments. Our ability to satisfy our obligations and planned expenditures will depend on our future operating performance, which will be affected by, among other things, prevailing economic conditions in the commodity markets of oil and natural gas, some of which are beyond our control.

The following tables summarize our statements of cash flows for the periods presented:

	For the Nine Months Ended September 30,
	2010			2009			Variance
Cash flows from operating activities	$	68,875		$	107,193		$	(38,318	)
Cash flows from investing activities
Capital expenditures - property and equipment		(313,710	)		(183,528	)		(130,182	)
Proceeds from sale of PVG units, net		139,120			-			139,120
Other, net		26,364			7,826			18,538
Net cash used in investing activities		(148,226	)		(175,702	)		27,476
Cash flows from financing activities
Dividends paid		(7,700	)		(7,278	)		(422	)
Distributions received from discontinued operations		11,218			34,932			(23,714	)
Repayments of borrowings, net		-			(339,542	)		339,542
Proceeds from sale of PVG units, net		199,125			118,080			81,045
Proceeds from the issuance of Senior notes, net		-			291,009			(291,009	)
Proceeds from the issuance of common stock, net		-			64,835			(64,835	)
Other, net		2,143			(9,687	)		11,830
Net cash provided by financing activities		204,786			152,349			52,437
Net increase in cash and cash equivalents	$	125,435		$	83,840		$	41,595

Cash Flows From Operating Activities

Cash settlements from our derivative portfolio were lower by $23.5 million during the nine months ended September 30, 2010 as compared to the prior year period. Primarily as a result of taxable gains realized upon the sale of our remaining interests in PVG during 2010, total tax payments were higher by $23.3 million compared to the prior year period. As a result of our organization restructuring program announced in the fourth quarter of 2009, we paid related costs of approximately $7 million during the 2010 period. In addition, interest payments on our debt instruments were $9.8 million higher during the nine months ended September 30, 2010 due primarily to the Senior Notes issued in the second quarter of 2009. These items were partially offset by the absence in 2010 of approximately $20 million in rig standby charges which were incurred and paid in the prior year period.

Cash Flows From Investing Activities

The cash used in investing activities consisted of $313.7 million of capital expenditures, offset partially by net proceeds of $139.1 million received from the sale in June 2010 of our remaining interests in PVG and $26.4 million from the sale of non-core assets, including our Gulf Coast properties.

We have expanded our drilling program in 2010 as compared to 2009. Significant activities are anticipated to occur in the fourth quarter of 2010 and continuing into 2011, including exploration activities in the Eagle Ford and Marcellus Shale plays. The following table sets forth costs related to our capital expenditures program for the periods presented:

	Nine Months Ended September 30,
	2010		2009
Oil and gas:
Development drilling	$	190,573	$	122,144
Exploration drilling		21,063		2,199
Seismic		8,573		1,195
Lease acquisitions, field projects and other		120,329		10,432
Pipeline and gathering facilities		887		8,374
		341,425		144,344
Other - Corporate		1,185		1,655
Total capital expenditures	$	342,610	$	145,999

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

	Nine Months Ended September 30,
	2010			2009
Total capital expenditures	$	342,610		$	145,999
Less:
Exploration expenses
Seismic		(8,573	)		(1,195	)
Other, primarily delay rentals		(2,213	)		(3,152	)
Changes in accrued capitalized costs		(11,065	)		40,313
Property received as consideration in sale transaction 1		(8,204	)		-
Add:
Capitalized interest		1,155			1,471
Other		-			92
Total cash paid for capital expenditures	$	313,710		$	183,528

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

Cash Flows From Financing Activities

The nine months ended September 30, 2010 includes the 2010 sale of 11.25 million common units of PVG for proceeds of $199.1 million, net of offering costs, which reduced our limited partner interest in PVG to 22.6%. Because we maintained a controlling financial interest in PVG, the proceeds from these transactions are reported as cash flows from financing activities. In addition, we received $11.2 million in distributions from PVG in 2010 as well as $2.1 million from the exercise of stock options by employees.

During the nine months ended September 30, 2009, we issued the Senior Notes for proceeds of $281.6 million, net of discount and issuance costs, and received proceeds of $64.8 million from the issuance of 3.5 million shares of our common stock. The proceeds from these transactions were used primarily to repay our borrowings under the Revolver. In addition, we received $118.1 million from the sale of 10 million common units of PVG in September of 2009.

Sources of Liquidity

Primarily as a result of asset dispositions during the nine months ended September 30, 2010, as well as certain financing activities that were completed during the latter half of 2009, we have a significant and diversified mix of liquidity available to us to fund our capital spending program for the remainder of 2010 and into 2011. As of September 30, 2010, we had available cash of $204.5 million. The significant increase over the 2009 year-end cash balance is attributable primarily to the proceeds we received from the dispositions of our interests in PVG and the Gulf Coast property sale in January 2010. As of September 30, 2010, we had $299.3 million of undrawn credit available to us under the Revolver. Our primary sources of liquidity are discussed below.

Debt and Credit Facilities

The following table summarizes our long-term debt:

	As of
	September 30,		December 31,
	2010		2009
Revolving credit facility	$	-	$	-
Senior notes, net of discount (principal amount of $300,000)		292,369		291,749
Convertible notes, net of discount (principal amount of $230,000)		212,155		206,678
	$	504,524	$	498,427

Revolving Credit Facility. The Revolver provides for a $300 million revolving credit facility and matures in November 2012. We have the option to increase the commitments under the Revolver by up to an additional $225 million upon the receipt of commitments from one or more lenders. The Revolver is limited by a borrowing base calculation, and the availability under the Revolver may not exceed the lesser of the aggregate commitments or the borrowing base. As of September 30, 2010, the borrowing base, which is redetermined semi-annually, was $420 million. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions and includes a $20 million sublimit for the issuance of letters of credit.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate (“LIBOR”), as adjusted for statutory reserve requirements for Eurocurrency liabilities (the “Adjusted LIBOR”), plus an applicable margin ranging from 2.000% to 3.000% or (ii) the greater of (a) the prime rate, (b) federal funds effective rate plus 0.5% and (c) the one-month Adjusted LIBOR plus 1.0%, in each case, plus an applicable margin (ranging from 1.000% to 2.000%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity.

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

Senior Notes. The Senior Notes bear interest at an annual rate of 10.375% and mature in June 2016. The Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Convertible Notes. The Convertible Notes are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. Interest on the Convertible Notes is payable semi-annually in arrears on May 15 and November 15 of each year. Unless they are converted or repurchased earlier, the Convertible Notes will mature in November 2012.

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

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

Interest Rate Swaps. We previously entered into interest rate swaps agreements, or Previous Interest Rate Swaps, to establish fixed rates on a portion of the previously outstanding borrowings under the Revolver until December 2010. As there are currently no amounts outstanding under the Revolver, we entered into an offsetting fixed-to-floating interest rate swap in December 2009 that effectively unwinds the Previous Interest Rate Swaps. In December 2009, we also entered into an a new interest rate swap to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the Senior Notes.

The following table describes our interest rate swap agreements as of September 30, 2010:

	Notional		Swap Interest Rates
Term	Amounts		Pay			Receive
Through December 2010	$	50,000		5.349	%	3-month LIBOR
Through December 2010	$	50,000	3-month LIBOR				0.53	%
Through June 2013	$	100,000	3-month LIBOR + 8.175		%		10.375	%

Asset Dispositions

During the nine months ended September 30, 2010, we completed two significant non-core asset dispositions that will provide support for the funding of our capital spending program for the remainder of 2010 and beyond. These dispositions were the sale of our remaining interests in PVG and the sale of our former Gulf Coast properties, which completed our efforts to exit activities in this region.

The following table summarizes the net cash realized from these dispositions during the nine months ended September 30, 2010:

	Net Cash
Asset Description	Realized
20.1 million common units of PVG 1	$	338,245
Oil and gas properties, including the Gulf Coast oil and gas assets 2		25,172
Other		1,192
	$	364,609

1 Of the total, $199,125 has been reported as cash received from financing activities and $139,120 has been reported as cash received from investing activities.

2 Excludes $2,280 received in 2009 as an initial deposit in connection the with sale of the Gulf Coast properties.

Commodity Price Risk Management

We actively manage our exposure to commodity price fluctuations by hedging the commodity price risk for our expected production through the use of derivatives, typically costless collar contracts. The level of our hedging activity and duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. During the nine months ended September 30, 2010, our commodity derivatives portfolio provided $25.3 million of cash inflows to offset lower than anticipated commodity prices received for our current year natural gas and oil production. For the remainder of 2010, we have hedged approximately 43% of our estimated natural gas production, at a weighted average floor price of $5.65 per MMBtu and a weighted average ceiling price of $8.77 per MMBtu.

Financial Condition

Covenant Compliance

The terms of the Revolver require us to maintain certain financial covenants as follows:

Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.0 to 1.0 reducing to 3.5 to 1.0 for periods ending on or after September 30, 2011. EBITDAX, which is a non-GAAP (generally accepted accounting principles) measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments, other non-cash charges or losses and the amount of cash distributions received from PVG and PVR.

The current ratio, as of the last day of any quarter, may not be less than 1.0 to 1.0. The current ratio is generally defined as current assets to current liabilities. Current assets and current liabilities attributable to derivative instruments are also excluded. In addition, current assets include the amount of any unused commitment under the Revolver.

As of September 30, 2010 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with the applicable covenants of the Revolver.

The following table summarizes the actual results of our covenant compliance for the period ended September 30, 2010:

			Actual
Description of Covenant	Covenant		Results
Total debt to EBITDAX		4.0		1.9
Current ratio		1.0		3.6

In the event that we would be in default of our covenants under the Revolver, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable on demand and would be reclassified as a component of current liabilities on our Condensed Consolidated Balance Sheets. In addition, the Revolver imposes limitations on dividends and distributions, as well as limits the ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.

Future Capital Needs and Commitments

Subject to changes in commodity prices and the availability of capital, we expect to expand our oil and gas operations over the next several years by continuing to execute a growth strategy dominated by development drilling and, to a lesser extent, exploration drilling, supplemented periodically with property and reserve acquisitions.

In 2010, we anticipate making total capital expenditures, excluding reserve acquisitions, of up to approximately $485 million. This represents a substantial increase over 2009 capital expenditures which totaled $172 million. The capital expenditures have been and will continue to be primarily funded by cash on hand supplemented by internally generated sources of cash and, if necessary, utilization of our available borrowing capacity under the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on industry conditions, cash flows provided by operating activities and the availability of capital.

Based on expenditures to date and forecasted activity for the fourth quarter, the 2010 capital expenditures program is anticipated to be allocated approximately as follows: Mid-Continent (40%), East Texas (26%), Appalachia (15%), Mississippi (11%) and all other areas (8%), including the Eagle Ford Shale play. This includes approximately $310 million for drilling and completions, with approximately 65% allocated to the oil and liquids rich Granite Wash and horizontal Cotton Valley, approximately 20% allocated to the Haynesville and Marcellus Shales and approximately 15% allocated to the Selma Chalk and other plays. We anticipate allocating up to $150 million to leasehold acquisitions including approximately 44% for the Marcellus Shale, approximately 18% for the Granite Wash and approximately 38% in East Texas, the Selma Chalk, the Eagle Ford Shale and other plays.

For future periods, we continue to assess funding needs for our growth opportunities in the context of our presently available debt capacity. We expect to continue to use a combination of cash on hand, cash flows from operating activities and debt financing, supplemented with equity issuances and the sale of other non-core assets, to fund our growth.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. As of September 30, 2010, we have recorded asset retirement obligations of $7.2 million attributable to these activities. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates which involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009 and remained unchanged as of September 30, 2010.

New Accounting Standards

See Note 17 to the Condensed Consolidated Financial Statements for a description of new accounting standards.

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are as follows:

•

Price Risk

•

Interest Rate Risk

As a result of our risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions. Sensitivity to these risks has heightened due to the current state of the financial and credit markets.

Price Risk

Our price risk management programs permit the utilization of derivative financial instruments (such as swaps, costless collars and three-way collars) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our anticipated production. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our derivative financial instruments are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At September 30, 2010, we reported a net commodity derivative asset of approximately $28 million. The contracts underlying such commodity derivative asset are with five counterparties, all of which are investment grade financial institutions, and such commodity derivative asset is substantially concentrated with two of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We have not paid or received collateral with respect to our derivative positions. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of September 30, 2010. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

In the nine months ended September 30, 2010, we reported consolidated net derivative gains of $44.4 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our commodity derivative contracts. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, NGL and crude oil prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the Condensed Consolidated Financial Statements for a further description of our derivatives programs.

The following table lists our commodity derivative agreements and their fair values as of September 30, 2010:

		Average						Fair Value
		Volume Per		Weighted Average Price				Asset
	Instrument	Day		Floor		Ceiling		(Liability)
Natural Gas:		(in MMBtu)
Fourth quarter 2010	Costless collars		50,000	$	5.65	$	8.77	$	7,854
First quarter 2011	Costless collars		50,000	$	5.65	$	8.77		6,396
Second quarter 2011	Costless collars		30,000	$	5.67	$	7.58		4,029
Third quarter 2011	Costless collars		30,000	$	5.67	$	7.58		3,807
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50		2,615
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		2,016
Second quarter 2012	Swaps		10,000	$	5.52				581
Third quarter 2012	Swaps		10,000	$	5.52				496

Crude Oil:		(barrels)
Fourth quarter 2010	Costless collars		500	$	60.00	$	74.75		(338	)
First quarter 2011	Costless collars		425	$	80.00	$	101.50		144
Second quarter 2011	Costless collars		425	$	80.00	$	101.50		152
Third quarter 2011	Costless collars		360	$	80.00	$	103.30		130
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		111

Settlements to be paid in subsequent period									-

The following table illustrates the estimated impact on the fair values of our derivative financial instruments and operating income attributable to hypothetical changes in the underlying commodity prices. This assumes that natural gas prices, crude oil prices and production volumes remain constant at anticipated levels. The estimated changes in operating income exclude potential cash receipts or payments in settling these derivative positions.

	Change of $1.00 per MMBtu of Natural Gas
	or $5.00 per Barrel of Crude Oil
	Increase			Decrease
Effect on the fair value of natural gas derivatives	$	(14.4	)	$	17.1
Effect on the fair value of crude oil derivatives	$	(0.6	)	$	0.6

Effect on remaining 2010 operating income, excluding natural gas derivatives	$	10.1		$	(10.1	)
Effect on remaining 2010 operating income, excluding crude oil derivatives	$	1.5		$	(1.5	)

Interest Rate Risk

Our only debt instrument subject to a variable interest rate is our Revolver. As of September 30, 2010, we had no outstanding indebtedness under the Revolver.

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2010. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2010, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

No changes were made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 6 Exhibits

10.1		Penn Virginia Corporation Seventh Amended and Restated 1999 Employee Stock Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 2, 2010).

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document

101.SCH		XBRL Taxonomy Extension Schema Document

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

101.LAB		XBRL Taxonomy Extension Label Linkbase Document

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		PENN VIRGINIA CORPORATION

Date:	November 4, 2010	By:	/s/ A. James Dearlove
			A. James Dearlove
			President, Chief Executive Officer and Chief Financial Officer

Date:	November 4, 2010	By:	/s/ Joan C. Sonnen
			Joan C. Sonnen
			Vice President and Controller