BAYTEX ENERGY USA, INC. - Quarter Report: 2011 September (Form 10-Q)

Unassociated Document

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, 2011

¨	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 28, 2011, 45,708,980 shares of common stock of the registrant were outstanding.

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2011

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, 2011 and 2010	1
	Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010	2
	Condensed Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010	3
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	4
	2. Basis of Presentation	4
	3. Acquisitions and Divestitures	4
	4. Accounts Receivable	5
	5. Derivative Instruments	5
	6. Property and Equipment	7
	7. Long-Term Debt	7
	8. Additional Balance Sheet Detail	10
	9. Fair Value Measurements	10
	10. Commitments and Contingencies	12
	11. Shareholders’ Equity and Comprehensive Income	13
	12. Share-Based Compensation	13
	13. Restructuring Activities	13
	14. Impairments	14
	15. Interest Expense	15
	16. Earnings per Share	15
	17. Discontinued Operations	16

Forward-Looking Statements		17

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

	Overview of Business	18
	Key Developments	19
	Results of Operations	21
	Liquidity and Capital Resources	33
	Environmental Matters	38
	Critical Accounting Estimates	38
	New Accounting Standards	38

3.	Quantitative and Qualitative Disclosures About Market Risk	39

4.	Controls and Procedures	40

	Part II - Other Information

1A.	Risk Factors	41

6.	Exhibits	42

Signatures		43

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,
	2011			2010			2011			2010
Revenues
Natural gas	$	34,171		$	47,476		$	113,660		$	134,283
Crude oil		37,147			13,396			75,278			38,117
Natural gas liquids (NGLs)		10,676			7,459			33,758			14,987
Gain on sales of property and equipment		71			280			523			616
Other		1,288			342			2,335			2,116
Total revenues		83,353			68,953			225,554			190,119
Operating expenses
Lease operating		8,458			9,256			29,522			27,148
Gathering, processing and transportation		2,952			3,625			11,261			10,165
Production and ad valorem taxes		3,391			5,309			11,289			12,684
General and administrative		12,635			13,445			38,941			44,297
Exploration		19,303			22,020			68,219			37,590
Depreciation, depletion and amortization		45,345			33,224			113,224			95,358
Impairments		-			35,127			71,071			36,251
Other		300			-			300			465
Total operating expenses		92,384			122,006			343,827			263,958
Operating loss		(9,031	)		(53,053	)		(118,273	)		(73,839	)
Other income (expense)
Interest expense		(14,206	)		(13,198	)		(41,833	)		(40,190	)
Loss on extinguishment of debt		(1,165	)		-			(25,403	)		-
Derivatives		11,498			15,113			19,827			44,410
Other		61			342			334			2,105
Loss from continuing operations before income taxes		(12,843	)		(50,796	)		(165,348	)		(67,514	)
Income tax benefit		6,125			20,637			60,372			27,024
Loss from continuing operations		(6,718	)		(30,159	)		(104,976	)		(40,490	)
Income from discontinued operations, net of tax		-			-			-			33,482
Gain on sale of discontinued operations, net of tax		-			-			-			49,612
Net income (loss)		(6,718	)		(30,159	)		(104,976	)		42,604
Less net income attributable to noncontrolling interests in discontinued operations		-			-			-			(28,090	)
Income (loss) attributable to Penn Virginia Corporation	$	(6,718	)	$	(30,159	)	$	(104,976	)	$	14,514

Earnings (loss) per share attributable to Penn Virginia Corporation - Basic:
Continuing operations	$	(0.15	)	$	(0.66	)	$	(2.29	)	$	(0.89	)
Discontinued operations		-			-			-			0.12
Gain on sale of discontinued operations		-			-			-			1.09
Net income (loss)	$	(0.15	)	$	(0.66	)	$	(2.29	)	$	0.32

Earnings (loss) per share attributable to Penn Virginia Corporation - Diluted:
Continuing operations	$	(0.15	)	$	(0.66	)	$	(2.29	)	$	(0.89	)
Discontinued operations		-			-			-			0.12
Gain on sale of discontinued operations		-			-			-			1.09
Net income (loss)	$	(0.15	)	$	(0.66	)	$	(2.29	)	$	0.32

Weighted average shares outstanding, basic		45,817			45,591			45,758			45,534
Weighted average shares outstanding, diluted		45,817			45,591			45,758			45,733

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)

	As of
	September 30,			December 31,
	2011			2010
Assets
Current assets
Cash and cash equivalents	$	3,577		$	120,911
Accounts receivable, net of allowance for doubtful accounts		75,736			72,378
Derivative assets		18,336			16,818
Other current assets		4,206			4,233
Total current assets		101,855			214,340
Property and equipment, net (successful efforts method)		1,752,261			1,705,584
Derivative assets		1,508			3,889
Other assets		21,383			20,787
Total assets	$	1,877,007		$	1,944,600

Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	98,303		$	99,661
Derivative liabilities		-			388
Deferred income taxes		3,113			4,318
Income taxes payable		3,506			2,627
Total current liabilities		104,922			106,994
Other liabilities		15,657			19,958
Deferred income taxes		269,082			330,836
Long-term debt		612,983			506,536

Commitments and contingencies (Note 10)

Shareholders’ equity:
Preferred stock of $100 par value – 100,000 shares authorized; none issued		-			-
Common stock of $0.01 par value – 128,000,000 shares authorized; shares issued of 45,706,545 and 45,556,854 as of September 30, 2011 and December 31, 2010, respectively		269			267
Paid-in capital		687,552			680,981
Retained earnings		187,761			300,473
Deferred compensation obligation		3,428			2,743
Accumulated other comprehensive loss		(836	)		(938	)
Treasury stock – 195,307 and 125,357 shares of common stock, at cost, as of September 30, 2011 and December 31, 2010, respectively		(3,811	)		(3,250	)
Total shareholders’ equity		874,363			980,276
Total liabilities and shareholders’ equity	$	1,877,007		$	1,944,600

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,
	2011			2010
Cash flows from operating activities
Net income (loss)	$	(104,976	)	$	42,604
Adjustments to reconcile net income (loss) to net cash provided by operating activities from continuing operations:
Income from discontinued operations before income taxes		-			(36,832	)
Gain on sale of discontinued operations before income taxes		-			(84,740	)
Non-cash portion of loss on extinguishment of debt		22,456			-
Depreciation, depletion and amortization		113,224			95,358
Impairments		71,071			36,251
Derivative contracts:
Net gains		(19,827	)		(44,410	)
Cash settlements		20,302			24,287
Deferred income tax benefit		(60,372	)		6,149
Gain on sales of property and equipment, net		(223	)		(151	)
Dry hole and unproved leasehold expense		52,457			26,501
Non-cash interest expense		5,812			9,089
Share-based compensation		5,629			6,400
Other, net		225			(341	)
Changes in operating assets and liabilities, net		(2,614	)		(11,290	)
Net cash provided by operating activities from continuing operations		103,164			68,875
Cash flows from investing activities
Capital expenditures - property and equipment		(318,274	)		(313,710	)
Proceeds from the sale of PVG units, net		-			139,120
Proceeds from sales of property and equipment, net		31,077			25,172
Other, net		100			1,192
Net cash used in investing activities for continuing operations		(287,097	)		(148,226	)
Cash flows from financing activities
Dividends paid		(7,736	)		(7,700	)
Proceeds from revolving credit facility borrowings		30,000			-
Repayment of revolving credit facility borrowings		(15,000	)		-
Proceeds from the issuance of Senior Notes due 2019		300,000			-
Repurchase of Convertible Notes		(232,963	)		-
Debt issuance costs paid		(8,850	)		-
Proceeds from the sale of PVG units, net		-			199,125
Distributions received from discontinued operations		-			11,218
Other, net		1,148			2,143
Net cash provided by financing activities from continuing operations		66,599			204,786
Cash flows from discontinued operations
Net cash provided by operating activities		-			77,759
Net cash used in investing activities		-			(18,112	)
Net cash used in financing activities		-			(59,647	)
Net cash provided by discontinued operations		-			-
Net increase (decrease) in cash and cash equivalents		(117,334	)		125,435
Cash and cash equivalents - beginning of period		120,911			79,017
Cash and cash equivalents - end of period	$	3,577		$	204,452
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	17,288		$	22,646
Income taxes (net of refunds received)	$	433		$	25,168

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, 2011

(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 Texas, Appalachia, the Mid-Continent and Mississippi.

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, 2010. Operating results for the nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011. Certain amounts for the 2010 period have been reclassified to conform to the current year presentation.

During the quarter ended September 30, 2011, no new accounting standards were adopted or were pending adoption that would have a significant impact on our Condensed Consolidated Financial Statements and Notes.

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 or disclosure in the Condensed Consolidated Financial Statements.

3. Acquisitions and Divestitures

Property Acquisitions

Eagle Ford Property Acquisitions

During 2011, we acquired approximately 7,300 net Eagle Ford Shale acres in Gonzales County, Texas for approximately $27 million. The acreage acquired in these transactions is in close proximity to the Eagle Ford Shale acreage that we acquired during 2010. We are the operator of the acquired acreage with an average working interest of approximately 81%.

Divestitures

Penn Virginia GP Holdings, L.P. (“PVG”) Unit Offering

In March and April 2010, we sold 11.25 million common units of PVG for proceeds of $199.1 million, net of offering costs. At the time, the transaction reduced our limited partner interest in PVG to 22.6% and resulted in a $70.2 million increase to noncontrolling interests and an $82.1 million increase to additional paid-in capital, net of income tax effects. Because we maintained a controlling financial interest in PVG, the proceeds received from these transactions were reported 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 “Gain on sale of discontinued operations, net of tax” caption on our Condensed Consolidated Statements of Income. Because we no longer held any interests in PVG, the proceeds received from this transaction were reported as cash flows from investing activities on our Condensed Consolidated Statements of Cash Flows, and we deconsolidated PVG from our Consolidated Financial Statements. The results of operations and cash flows attributable to PVG for the 2010 period are presented in these Condensed Consolidated Financial Statements and Notes as discontinued operations.

Oil and Gas Properties

In August 2011, we sold a substantial portion of our Arkoma Basin assets for approximately $30 million, excluding transaction costs and subject to customary purchase and sale adjustments. We recognized an insignificant gain in connection with the transaction in the third quarter of 2011, following an impairment of approximately $71 million in the second quarter of 2011. The sale, which was effective July 1, 2011, included primarily natural gas and coal bed methane properties of approximately 73,000 net acres in Oklahoma and Texas with proved reserves of approximately 35.8 billion cubic feet of natural gas equivalent as well as related inventory and equipment. Additional post-closing adjustments, which we expect to be immaterial, may be recognized during the fourth quarter of 2011.

In January 2010, we completed the sale of all of our oil and gas properties in the Gulf Coast region (southern Texas and Louisiana) for cash proceeds of $23.2 million, net of transaction costs and certain purchase and sale adjustments, and the receipt of certain oil and gas properties located in the Gwinville field in northern Mississippi valued at $8.2 million.

4. Accounts Receivable

The following table summarizes our accounts receivable by type as of the periods presented:

	September 30,			December 31,
	2011			2010
Revenue customers	$	53,917		$	44,783
Joint interest partners		20,344			23,526
Other		1,756			4,442
		76,017			72,751
Less: Allowance for doubtful accounts		(281	)		(373	)
	$	75,736		$	72,378

For the nine months ended September 30, 2011 and 2010, five customers accounted for $135.9 million and $123.0 million, or approximately 61% and 66%, respectively, of our total consolidated product revenues. As of September 30, 2011 and December 31, 2010, $24.8 million and $32.9 million, or approximately 33% and 45%, respectively, of our consolidated accounts receivable, including joint interest billings, related to these customers. No significant uncertainties exist related to the collectability of amounts owed to us by these customers.

5. Derivative Instruments

We utilize derivative instruments to mitigate our financial exposure to natural gas and crude oil price volatility as well as interest rates attributable to our debt instruments. We are not engaged in the trading of derivative instruments for speculative purposes. The derivative instruments, which are placed with financial institutions that we believe are acceptable credit risks, generally take the form of costless collars and swaps. Our derivative instruments are not formally designated as hedges and, therefore, we recognize the changes in fair value in earnings currently as a component of the Derivatives caption on our Condensed Consolidated Statements of Income.

Commodity Derivatives

We determine the fair values of our oil and gas derivative instruments using third-party quoted forward prices for NYMEX Henry Hub natural 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 commodity derivative positions as of September 30, 2011:

		Average
		Volume Per		Weighted Average Price				Fair Value
	Instrument	Day		Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)		($/MMBtu)
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50	$	4,047	$	-
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		3,405		-
Fourth quarter 2011	Swaps		10,000	$	5.01				1,114		-
First quarter 2012	Swaps		10,000	$	5.10				881		-
Second quarter 2012	Swaps		20,000	$	5.31				2,117		-
Third quarter 2012	Swaps		20,000	$	5.31				1,952		-
Fourth quarter 2012	Swaps		10,000	$	5.10				557		-

Crude Oil:		(barrels)		($/barrel)
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		168		-
First quarter 2012	Costless collars		500	$	100.00	$	120.00		983		-
Second quarter 2012	Costless collars		500	$	100.00	$	120.00		986		-
Third quarter 2012	Costless collars		500	$	100.00	$	120.00		974		-
Fourth quarter 2012	Costless collars		500	$	100.00	$	120.00		951		-
Fourth quarter 2011	Swaps		500	$	109.00				1,709		-
								$	19,844	$	-

Interest Rate Swaps

In December 2009, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the face amount of the outstanding obligation under the 10.375% Senior Notes due 2016 (“2016 Senior Notes”). During August 2011, we terminated this agreement and received $2.9 million in cash proceeds.

The following table sets forth the terms and positions of our interest rate swap assets as of the periods presented:

	Notional		Swap Interest Rates 1				September 30,		December 31,
Term	Amount		Pay	Receive			2011		2010
Through June 2013	$	100,000	LIBOR + 8.175%		10.375	%	$	-	$	2,590

1 References to LIBOR represent the 3-month rate.

Financial Statement Impact of Derivatives

The impact of our derivative activities on income is included in the Derivatives caption on our Condensed Consolidated Statements of Income. The following table summarizes the effects of our derivative activities for the periods presented:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Impact by contract type:
Commodity contracts	$	11,293		$	13,381		$	18,598		$	38,733
Interest rate contracts		205			1,732			1,229			5,677
	$	11,498		$	15,113		$	19,827		$	44,410
Realized and unrealized impact:
Cash received (paid) for:
Commodity contract settlements	$	5,607		$	7,433		$	16,484		$	25,257
Interest rate contract settlements		2,920			(630	)		3,818			(970	)
		8,527			6,803			20,302			24,287
Unrealized gains (losses) attributable to:
Commodity contracts		5,686			5,948			2,114			13,476
Interest rate contracts		(2,715	)		2,362			(2,589	)		6,647
		2,971			8,310			(475	)		20,123
	$	11,498		$	15,113		$	19,827		$	44,410

The effects of derivative gains (losses) and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net income to net cash provided by operating activities from continuing operations. These items are recorded in the “Derivative contracts: Net gains” and “Derivative contracts: Cash settlements” captions on our Condensed Consolidated Statements of Cash Flows.

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 as of the periods presented:

		Fair Values as of
		September 30, 2011				December 31, 2010
Derivative		Derivative		Derivative		Derivative		Derivative
Instrument	Balance Sheet Location	Assets		Liabilities		Assets		Liabilities

Interest rate contracts	Derivative assets/liabilities - current	$	-	$	-	$	1,743	$	-
Commodity contracts	Derivative assets/liabilities - current		18,336		-		15,075		388
			18,336		-		16,818		388

Interest rate contracts	Derivative assets/liabilities - noncurrent		-		-		847		-
Commodity contracts	Derivative assets/liabilities - noncurrent		1,508		-		3,042		-
			1,508		-		3,889		-
		$	19,844	$	-	$	20,707	$	388

As of September 30, 2011, we reported a commodity derivative asset of $19.8 million. The contracts associated with this position are with five counterparties, all of which are investment grade financial institutions, and are substantially concentrated with three of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

6. Property and Equipment

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

	September 30,			December 31,
	2011			2010
Oil and gas properties:
Proved	$	2,248,553		$	2,139,894
Unproved, net of amortization		162,962			171,303
Total oil and gas properties		2,411,515			2,311,197
Other property and equipment		16,751			15,589
Total property and equipment		2,428,266			2,326,786
Accumulated depreciation, depletion and amortization		(676,005	)		(621,202	)
	$	1,752,261		$	1,705,584

7. Long-Term Debt

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

	September 30,		December 31,
	2011		2010
Revolving credit facility	$	15,000	$	-
Senior notes due 2016, net of discount (principal amount of $300,000)		293,281		292,487
Senior notes due 2019		300,000		-
Convertible notes due 2012, net of discount (principal amount of $4,915 and $230,000)		4,702		214,049
	$	612,983	$	506,536

Revolving Credit Facility

In August 2011, we entered into a new five-year revolving credit facility (the “Revolver”) maturing in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has a borrowing base of $380 million, which has been adjusted to reflect the sale of our Arkoma Basin assets. The borrowing base is redetermined semi-annually. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions.

Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities (the “Adjusted LIBOR”), plus an applicable margin ranging from 1.500% to 2.500% or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). The applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity. During the quarter ended September 30, 2011, the effective interest rate on the borrowings under the Revolver was 1.8%.

The Revolver includes both current ratio and leverage ratio financial covenants. The current ratio is defined in the Revolver to include, among other things, adjustments for undrawn availability and may not be less than 1.0 to 1.0. The ratio of total net debt to EBITDAX, a non-GAAP financial measure defined in the Revolver, may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013.

In addition to the borrowings disclosed in the table above, we have letters of credit of $1.4 million outstanding as of September 30, 2011. As of September 30, 2011, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and such letters of credit, was approximately $284 million.

The Revolver is guaranteed by Penn Virginia and all of our material 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.

The guarantees provided by the Guarantor Subsidiaries under the Revolver as well as those provided for the senior indebtedness described below are full and unconditional and joint and several. Substantially all of our consolidated assets are held by the Guarantor Subsidiaries. The parent company and its non-guarantor subsidiaries have no material independent assets or 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.

2016 Senior Notes

The 2016 Senior Notes were originally sold at 97% of par equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes bear interest at an annual rate of 10.375% payable semi-annually in arrears on June 15 and December 15 of each year. Beginning in June 2013, we may redeem all or part of the 2016 Senior Notes at a redemption price beginning at 105.188% of the principal amount and reducing to 100% in June 2015 and thereafter. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

2019 Senior Notes

The Senior Notes due 2019 (“2019 Senior Notes”), which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable semi-annually in arrears on April 15 and October 15 of each year. Beginning in April 2015, we may redeem all or part of the 2019 Senior Notes at a redemption price beginning at 103.625% of the principal amount and reducing to 100% in June 2017 and thereafter. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Convertible Notes

The 4.50% Convertible Senior Subordinated Notes due 2012 (“Convertible Notes”) bear interest at an annual rate of 4.50% payable on May 15 and November 15 of each year. 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. 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 rank senior in right of payment to any of our future junior subordinated indebtedness and structurally rank junior to all existing and future indebtedness of our Guarantor Subsidiaries.

The Convertible Notes are represented by a liability component which is included in 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 effective interest rate on the liability component of the Convertible Notes for all periods presented was 8.5%.

In connection with a tender offer completed in April 2011, the Company repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, representing a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded from the net proceeds of the 2019 Senior Notes offering.

As a result of the tender offer, we recognized a pre-tax loss on extinguishment of debt of $25.9 million during the three months ended June 30, 2011, of which $24.2 million was charged to earnings and the remaining $1.7 million was charged directly to shareholders’ equity. The loss charged to earnings was determined as follows:

Cash paid to repurchase principal:
Allocated to liability component	$	231,331
Allocated to equity component		1,632
	$	232,963

Carrying value of liability component tendered:
Principal amount of Convertible Notes tendered	$	225,085
Pro rata share of original issue discount		(13,429	)
	$	211,656

Loss on extinguishment of debt:
Excess of liability component over carrying value	$	19,675
Write-off of pro rata share of debt issuance costs		2,147
Non-cash portion of loss on extinguishment		21,822
Transaction costs and fees paid		2,416
Pre-tax loss on extinguishment	$	24,238

The following table summarizes the carrying amount of the components of the Convertible Notes as of the periods presented:

	September 30,			December 31,
	2011			2010
Principal	$	4,915		$	230,000
Unamortized discount		(213	)		(15,951	)
Net carrying amount of liability component	$	4,702		$	214,049
Carrying amount of equity component	$	35,201		$	36,850

The following table summarizes the amounts recognized as components of interest expense attributable to the Convertible Notes for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Contractual interest expense	$	55	$	2,588	$	3,064	$	7,763
Accretion of original issue discount		43		1,868		2,308		5,477
Amortization of debt issuance costs		7		300		396		941
	$	105	$	4,756	$	5,768	$	14,181

In connection with the original 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.

In August 2011, we entered into a partial unwind transaction with one of the Option Counterparties in which we received cash proceeds of less than $0.1 million. The transaction resulted in a reduction of the number of options outstanding attributable to the Note Hedges as well as a reduction in the number of outstanding Warrants. The effect of this transaction resulted in an increase to additional paid-in capital.

8. Additional Balance Sheet Detail

The following table summarizes components of selected balance sheet accounts as of the periods presented:

	September 30,		December 31,
	2011		2010
Other current assets:
Tubular inventory and well materials	$	3,969	$	3,600
Prepaid expenses		237		633
	$	4,206	$	4,233
Other assets:
Debt issuance costs	$	17,660	$	14,300
Long-term investments - SERP		3,674		6,440
Other		49		47
	$	21,383	$	20,787
Accounts payable and accrued liabilities:
Trade accounts payable	$	25,202	$	33,831
Drilling costs		25,285		31,770
Royalties		13,140		9,308
Production and franchise taxes		5,146		6,012
Compensation		6,947		9,631
Interest		19,319		2,977
Other		3,264		6,132
	$	98,303	$	99,661
Other liabilities:
Asset retirement obligations	$	6,019	$	7,364
Pension		1,666		1,766
Postretirement health care		2,966		2,976
Deferred compensation		3,806		6,952
Other		1,200		900
	$	15,657	$	19,958

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, 2010.

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, 2011, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

The following table summarizes the fair value of our long-term debt with fixed interest rates, which is estimated based on the published market prices for the same or similar issues as of the periods presented:

	September 30, 2011				December 31, 2010
	Fair		Carrying		Fair		Carrying
	Value		Value		Value		Value
Senior Notes due 2016	$	315,000	$	293,281	$	335,712	$	292,487
Senior Notes due 2019		279,000		300,000		-		-
Convertible Notes		4,995		4,702		225,975		214,049
	$	598,995	$	597,983	$	561,687	$	506,536

Recurring Fair Value Measurements

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

	September 30, 2011
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2		Level 3
Assets:
Publicly traded equity securities	$	3,674		$	3,674		$	-	$	-
Commodity derivative assets - current		18,336			-			18,336		-
Commodity derivative assets - noncurrent		1,508			-			1,508		-

Liabilities:
Deferred compensation - noncurrent liability		(3,802	)		(3,802	)		-		-
Commodity derivative liabilities - current		-			-			-		-
Totals	$	19,716		$	(128	)	$	19,844	$	-

	December 31, 2010
	Fair Value			Fair Value Measurement Classification
Description	Measurement			Level 1			Level 2			Level 3
Assets:
Publicly traded equity securities	$	6,440		$	6,440		$	-		$	-
Interest rate swap assets - current		1,743			-			1,743			-
Interest rate swap assets - noncurrent		847			-			847			-
Commodity derivative assets - current		15,075			-			15,075			-
Commodity derivative assets - noncurrent		3,042			-			3,042			-

Liabilities:
Deferred compensation - noncurrent liability		(6,948	)		(6,948	)		-			-
Commodity derivative liabilities - current		(388	)		-			(388	)		-
Totals	$	19,811		$	(508	)	$	20,319		$	-

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

•

Publicly traded equity securities: We hold various publicly traded equity securities 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 instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub natural 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 determine the fair values of our interest rate swaps using an income approach valuation technique that connects 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 are based on quoted market prices, which are level 1 inputs.

Non-Recurring Fair Value Measurements

The most significant non-recurring fair value measurements include the fair value of proved properties, tubular inventory and well materials for purposes of impairment testing and the initial determination of asset retirement obligations (“AROs”). The factors used to determine fair value for purposes of impairment testing 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. Because these significant fair value inputs are typically not observable, we have categorized the amounts as level 3 inputs.

The determination of the fair value of AROs is based upon regional market and facility specific information. The amount of an ARO and the costs capitalized represent the estimated future cost to satisfy the abandonment obligation using current prices that are escalated by an assumed inflation factor after discounting the future cost back to the date that the abandonment obligation was incurred using a rate commensurate with the risk, which approximates our cost of funds. Because these significant fair value inputs are typically not observable, we have categorized the initial fair value estimates as level 3 inputs.

In addition to these non-recurring fair value measurements, we utilized fair value measurements in the determination of the loss on the extinguishment of approximately 98% of our Convertible Notes. In connection with that determination, we were required to allocate the cash paid to repurchase the Convertible Notes to its liability and equity components. The allocation to the liability component was based on the fair value of a comparable debt instrument that has no conversion feature. The residual amount of cash paid to repurchase the Convertible Notes was allocated to the equity component.

10. Commitments and Contingencies

Commitments

Our most significant commitments consist of the purchase of oil and gas well drilling services, fracturing chemicals and compression services, capacity utilization under firm transportation service agreements and operating lease rentals for equipment and office space, as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2010.

Contingencies - Legal and Regulatory

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 quarter ended September 30, 2011, we recorded a $0.3 million reserve for litigation attributable to certain properties that were previously sold. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of September 30, 2011. During 2010, we also established a $0.5 million reserve for a sales and use tax audit contingency, which was ultimately resolved during the quarter ended September 30, 2011 for $0.3 million. In addition, as of September 30, 2011, we have an ARO liability of approximately $6.0 million attributable to the plugging of abandoned wells.

11. Shareholders’ Equity and Comprehensive Income

The following table is a reconciliation of the carrying amounts 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 as of December 31, 2010	$	980,276		$	-		$	980,276
Dividends paid ($0.16875 per share)		(7,736	)		-			(7,736	)
Other changes to shareholders' equity		6,697			-			6,697
Comprehensive income:
Net loss		(104,976	)		-			(104,976	)	$	(104,976	)
Other, net of tax		102			-			102			102
Balance as of September 30, 2011	$	874,363		$	-		$	874,363		$	(104,874	)
Balance as of 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 as of September 30, 2010	$	1,002,891		$	-		$	1,002,891		$	43,012

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 granted under our stock compensation plans 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,
	2011		2010		2011		2010
Stock option plans	$	1,354	$	1,319	$	4,141	$	4,704
Common, deferred and restricted stock and restricted stock unit plans		466		392		1,488		1,696
	$	1,820	$	1,711	$	5,629	$	6,400

13. Restructuring Activities

During August 2011, we initiated an organizational restructuring due primarily to our decision to exit the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. This restructuring resulted in the termination of approximately 40 employees, most of whom were based out of our Tulsa, Oklahoma office, as well as certain corporate positions in connection with a reallocation of administrative functions. In addition, we expect to close our regional office in Tulsa, Oklahoma during the fourth quarter of 2011.

During 2009 and 2010, we implemented an organization restructuring in connection with our transformation to a pure play development, exploration and production company. The restructuring resulted in the termination of approximately 30 employees and the transfer of certain corporate and division operations functions from our former Kingsport, Tennessee location to our Houston, Texas and Pittsburgh and Radnor, Pennsylvania locations. We incurred special termination benefit costs, relocation costs and other incremental costs associated with staffing and expanding our office locations. Amounts incurred during the periods ended during 2010 are solely attributable to this restructuring.

The following table summarizes the costs incurred by each restructuring action for the nine months ended September 30, 2011:

	Mid-Continent		2009/2010
	Organization		Organization
	Restructuring		Restructuring		Total
Termination benefits	$	1,451	$	-	$	1,451
Employee and office relocation costs		101		71		172
	$	1,552	$	71	$	1,623

These restructuring charges are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Income and are comprised of the following for the periods presented:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Termination benefits	$	1,451	$	-	$	1,451	$	867
Employee and office relocation costs		102		527		172		1,202
Other incremental costs		-		260		-		865
Facility lease-related charges		-		-		-		3,500
	$	1,553	$	787	$	1,623	$	6,434

The following table summarizes our restructuring-related obligations as of and for the nine months ended September 30:

	2011			2010
Balance at beginning of period	$	64		$	529
Termination benefits accrued		1,451			867
Employee, office and other costs accrued		172			5,567
Cash payments		(420	)		(6,963	)
Balance at end of period	$	1,267		$	-

14. Impairments

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Oil and gas properties	$	-	$	32,627	$	71,071	$	32,627
Other		-		2,500		-		3,624
	$	-	$	35,127	$	71,071	$	36,251

During the three months ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties. As disclosed in Note 3, we completed the sale of these properties in August 2011. During the three and nine months ended September 30, 2010, we recognized 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, and also recognized impairment charges attributable to certain tubular inventory and well materials triggered primarily by declines in asset quality.

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,
	2011			2010			2011			2010
Interest on borrowings and related fees	$	13,581		$	10,758		$	37,448		$	32,245
Accretion on original issue discount		315			1,986			3,103			6,097
Amortization of debt issuance costs		747			883			2,709			2,992
Capitalized interest		(437	)		(438	)		(1,427	)		(1,155	)
Other, net		-			9			-			11
	$	14,206		$	13,198		$	41,833		$	40,190

16. Earnings per Share

The following table provides a reconciliation of the components 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,
	2011			2010			2011			2010
Loss from continuing operations	$	(6,718	)	$	(30,159	)	$	(104,976	)	$	(40,490	)
Income from discontinued operations, net of tax 1		-			-			-			33,482
Gain on sale of discontinued operations		-			-			-			49,612
Less: Net income attributable to noncontrolling interests		-			-			-			(28,090	)
Net income (loss) attributable to common shareholders	$	(6,718	)	$	(30,159	)	$	(104,976	)	$	14,514
Less: Portion of subsidiary net income allocated to undistributed share-basd compensation awards, net of tax		-			-			-			(28	)
	$	(6,718	)	$	(30,159	)	$	(104,976	)	$	14,486

Weighted-average shares, basic		45,817			45,591			45,758			45,534
Effect of dilutive securities 2		-			-			-			199
Weighted-average shares, diluted		45,817			45,591			45,758			45,733

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

For both the three and nine months ended September 30, 2011, 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. Discontinued Operations

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. Our ownership interests in PVR were held principally through our general and limited partner interests in PVG. During June 2010, we disposed of our remaining ownership interests in PVG and, indirectly, our interests in PVR.

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. The table below reflects the results of operations of PVG for the periods presented.

	Nine Months Ended September 30,
	2011		2010
Revenues	$	-	$	303,206

Income from discontinued operations before taxes	$	-	$	36,832
Income tax expense 1		-		(3,350	)
Income from discontinued operations, net of taxes	$	-	$	33,482

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

During the third quarter of 2011, we terminated certain agreements under which PVR provided marketing and gas gathering and processing services to us. We continue to sell gas to PVR for resale at PVR’s Crossroads plant in east Texas.

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, or Exchange Act. 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 and oil;

•

our ability to develop, explore for, acquire and replace oil and gas reserves and sustain production;

•

any impairments, write-downs or write-offs of our reserves or assets;

•

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

•

reductions in the borrowing base under our revolving credit facility;

•

our ability to contract for drilling rigs, supplies and services at reasonable costs;

•

our ability to obtain adequate pipeline transportation capacity for our oil and gas production at reasonable costs and to sell the production at, or at reasonable discounts to, market prices;

•

the uncertainties inherent in projecting future rates of production for our wells and the extent to which actual production differs from estimated proved oil and gas reserves;

•

drilling and operating risks;

•

our ability to compete effectively against other independent and major oil and natural gas companies;

•

uncertainties related to expected benefits from acquisitions of oil and natural gas properties;

•

environmental liabilities that are not covered by an effective indemnity or insurance;

•

the timing of receipt of necessary regulatory permits;

•

the effect of commodity and financial derivative arrangements;

•

our ability to maintain adequate financial liquidity and to access adequate levels of capital on reasonable terms;

•

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

•

our ability to retain or attract senior management and key technical employees;

•

counterparty risk related to their ability to meet their future obligations;

•

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

•

uncertainties relating to general domestic and international economic and political conditions; and

•

other risks set forth in our Annual Report on Form 10-K for the year ended December 31, 2010.

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 Texas, Appalachia, the Mid-Continent and Mississippi regions of the United States. As of June 30, 2011, we had proved natural gas and oil reserves of approximately 892 billion cubic feet equivalent, or Bcfe, adjusted for the sale of our Arkoma Basin properties in August 2011 as discussed below. Our current operations include primarily the drilling of unconventional development opportunities and exploratory prospects.

The primary development play types that we are currently focused on include the Eagle Ford Shale play in South Texas and the horizontal Granite Wash play in the Mid-Continent. We recently drilled several exploratory wells in the Marcellus Shale play in Appalachia and plan to drill additional wells in 2012 in order to determine whether our leasehold acreage position 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,
	2011			2010			2011			2010
Total production (MMcfe)		11,947			13,280			35,817			34,093
Daily production (MMcfe per day)		129.9			144.3			131.2			124.9

Realized prices per Mcfe, as reported	$	6.86		$	5.15		$	6.22		$	5.50
Realized prices per Mcfe, adjusted for derivatives	$	7.33		$	5.70		$	6.68		$	6.24

Product revenues, as reported	$	81,994		$	68,331		$	222,696		$	187,387
Product revenues, as adjusted for derivatives	$	87,601		$	75,763		$	239,180		$	212,644

Operating loss	$	(9,031	)	$	(53,053	)	$	(118,273	)	$	(73,839	)
Interest expense	$	14,206		$	13,198		$	41,833		$	40,190

Cash provided by operating activities	$	39,405		$	23,206		$	103,164		$	68,875
Cash paid for capital expenditures	$	107,193		$	145,629		$	318,274		$	313,710

Cash and cash equivalents at end of period							$	3,577		$	204,452
Debt outstanding, net of discounts, at end of period							$	612,983		$	504,524
Credit available under revolving credit facility at end of period 1							$	283,600		$	299,268

Net development wells drilled		9.4			11.7			23.8			32.5
Net exploratory wells drilled		0.1			1.2			6.5			2.2

1 As reduced by outstanding borrowings and letters of credit.

Key Developments

Through the date of filing this Quarterly Report on Form 10-Q, the following general business developments and corporate actions had an impact on the financial reporting and disclosure of our results of operations and financial position: (i) drilling results in the Eagle Ford Shale, Marcellus Shale and Granite Wash plays, (ii) selling our Arkoma Basin assets and related restructuring activities, (iii) entering into a new five-year revolving credit facility, or Revolver, (iv) acquiring properties in the Eagle Ford Shale play and (v) offering and selling $300 million of our 7.25% Senior Notes due 2019, or 2019 Senior Notes, together with the tender offer to repurchase our 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes.

Drilling Results and Future Development

During the nine months ended September 30, 2011, we drilled a total of 30.3 net wells, including 17.5 net wells in the Eagle Ford Shale, 4.3 net wells in the Marcellus Shale and 8.5 net wells in the Mid-Continent region, primarily in the Granite Wash.

Through October 2011, we have drilled 26 Eagle Ford Shale wells. A total of 20 (16.7 net) have been turned in line and are producing at an average peak gross rate of approximately 1,012 barrels of oil equivalent per day, or BOEPD. The natural gas associated with these wells is yielding approximately 145 barrels of natural gas liquids, or NGLs, per million cubic feet, or MMcf. In June 2011, our natural gas midstream service provider connected our wells in the northern portion of our Eagle Ford Shale acreage to its pipeline and processing facilities resulting in the recognition of sales revenue associated with NGLs and residue gas production. We expect that the wells in the southern portion of our acreage will be connected in November 2011. We expect to continue drilling in this region for the remainder of 2011 and beyond. In July 2011, we extended our agreement with a hydraulic fracturing services contractor to provide these services in the Eagle Ford Shale, as well as other plays in East Texas and Oklahoma, through July 2012. We have allocated approximately $85 million during the fourth quarter of 2011 for development drilling capital expenditures primarily in the Eagle Ford Shale.

In 2011, we drilled four and completed three horizontal test wells in the Marcellus Shale located in the central portion of our approximately 35,000 net acreage position in Potter and Tioga counties, Pennsylvania. The completed wells resulted in an average rate that ranged from 1.7 to 2.7 MMcf per day over a 72-hour test period. These wells are now connected to a pipeline, and production began in October 2011. Completion of the fourth well has been deferred. We will monitor long-term production to determine if the reserves can support a development program in this immediate area. We are also evaluating alternative drilling techniques with respect to the direction of the laterals and completion procedures in this relatively undeveloped geological area. We plan to apply these new techniques to the drilling and completion of two horizontal test wells in 2012.

In the Mid-Continent region, we successfully completed 5.8 net development wells in the Granite Wash. We plan to continue our Granite Wash development program in this region, primarily as a non-operator. Our exploratory program resulted in 4 dry holes (2.7 net) at an aggregate cost of $18.9 million during the nine months ended September 30, 2011. We do not plan any further exploratory activities in the Mid-Continent region during 2011.

Disposition of Arkoma Basin Properties and Related Restructuring Action

In August 2011, we sold a substantial portion of our Arkoma Basin assets for approximately $30 million, excluding transaction costs and subject to customary purchase and sale adjustments. We recognized an insignificant gain in connection with the transaction in the third quarter of 2011, following an impairment of approximately $71 million in the second quarter of 2011. The sale, which was effective July 1, 2011, included primarily natural gas and coal bed methane properties of approximately 73,000 net acres in Oklahoma and Texas with proved reserves of approximately 35.8 Bcfe as well as related inventory and equipment. Additional post-closing adjustments, which we expect to be immaterial, may be recognized during the fourth quarter of 2011. On an annual basis, these properties represent production of approximately 3 Bcfe.

During August 2011, we initiated an organizational restructuring due primarily to our decision to exit the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. This restructuring and consolidation resulted in the termination of approximately 40 employees, most of whom were based out of our Tulsa, Oklahoma office, as well as certain corporate positions in connection with a reallocation of administrative functions. In addition, we plan to close our regional office in Tulsa, Oklahoma during the fourth quarter of 2011.

Completion of a New Credit Facility

In August 2011, we entered into the Revolver which provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has a borrowing base of $380 million which takes into account the Arkoma Basin sale discussed above. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The financial covenant that determines the permitted leverage ratio (net debt divided by Adjusted EBITDAX, as defined in the Revolver) increased to 4.5 through periods ending on or before June 30, 2013, after which it will be 4.0.

The Revolver is guaranteed by Penn Virginia and all of our material 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. The Revolver will mature in August 2016.

Property Acquisitions

During 2011, we acquired approximately 7,300 net Eagle Ford Shale acres in Gonzales County, Texas for approximately $27 million. This acreage is in close proximity to the Eagle Ford Shale acreage that we acquired during 2010. We are the operator of the acquired acreage with an average working interest of approximately 81%. As of October 31, 2011, our leasehold position in the Eagle Ford Shale is approximately 17,900 gross acres (14,700 net). We continue efforts to expand our Eagle Ford Shale position in Gonzales County and other prospective areas in the play through additional leasing and selective acquisitions.

Senior Note Offering and Tender Offer to Repurchase Convertible Notes

In April 2011, we completed the offering of our 2019 Senior Notes. Total proceeds received from the offering were $293.5 million, net of underwriting and debt issuance costs. We used $237.1 million of the proceeds to repurchase approximately 98% of our Convertible Notes plus accrued interest, and we have a total of $4.9 million (principal amount) of Convertible Notes currently outstanding. We used the remainder of the proceeds to provide working capital for general corporate purposes, including capital expenditures.

Results of Operations

Three Months Ended September 30, 2011 Compared to the Three Months Ended September 30, 2010

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

	Three Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		8,051			10,890			(2,838	)		(26	)%
Crude oil (MBbl)		427			189			238			126	%
NGL (MBbl)		222			210			13			6	%
Total production (MMcfe)		11,947			13,280			(1,333	)		(10	)%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.24		$	4.36		$	(0.12	)		(3	)%
Crude oil ($/Bbl)		87.03			70.97			16.06			23	%
NGL ($/Bbl)		48.00			35.57			12.43			35	%
Total ($/Mcfe)	$	6.86		$	5.15		$	1.71			33	%

Revenues
Natural gas	$	34,171		$	47,476		$	(13,305	)		(28	)%
Crude oil		37,147			13,396			23,751			177	%
NGL		10,676			7,459			3,217			43	%
Total product revenues		81,994			68,331			13,663			20	%
Gain on sales of property and equipment		71			280			(209	)		(75	)%
Other income		1,288			342			946			277	%
Total revenues		83,353			68,953			14,400			21	%

Operating Expenses
Lease operating		8,458			9,256			798			9	%
Gathering, processing and transportation		2,952			3,625			673			19	%
Production and ad valorem taxes		3,391			5,309			1,918			36	%
General and administrative		12,635			13,445			810			6	%
Exploration		19,303			22,020			2,717			12	%
Depreciation, depletion and amortization		45,345			33,224			(12,121	)		(36	)%
Impairments		-			35,127			35,127		NM
Other		300			-			(300	)	NM
Total operating expenses		92,384			122,006			29,622			24	%

Operating loss		(9,031	)		(53,053	)		44,022			83	%
Other income (expense)
Interest expense		(14,206	)		(13,198	)		(1,008	)		(8	)%
Loss on extinguishment of debt		(1,165	)		-			(1,165	)	NM
Derivatives		11,498			15,113			(3,615	)		(24	)%
Other		61			342			(281	)		(82	)%
Loss from continuing operations before income taxes		(12,843	)		(50,796	)		37,953		NM
Income tax benefit		6,125			20,637			(14,512	)		(70	)%
Loss from continuing operations	$	(6,718	)	$	(30,159	)	$	23,441		NM

NM - Not meaningful

Production

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

	Three Months Ended September 30,				Favorable			Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
Texas		4,908		4,024		884			53.3		43.7		9.6			22	%
Appalachia		2,277		2,704		(427	)		24.8		29.4		(4.6	)		(16	)%
Mid-Continent		3,201		4,474		(1,273	)		34.8		48.6		(13.8	)		(28	)%
Mississippi		1,561		2,078		(517	)		17.0		22.6		(5.6	)		(25	)%
Total production		11,947		13,280		(1,333	)		129.9		144.3		(14.4	)		(10	)%

The decline in total production was due primarily to the lack of any significant natural gas drilling since mid-2010 and the subsequent natural production declines as well as the effect of the sale of our Arkoma Basin properties. The natural gas production decline was partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. While higher than the prior year period, NGL production in the Granite Wash during the 2011 period has been adversely impacted since July 2011 by a fire at a third-party processing plant. Approximately 33% of total production on an equivalent basis in the three months ended September 30, 2011 was attributable to oil and NGLs, an increase of 63% compared to the corresponding period in 2010. The shift in production mix reflects our focus on emerging oil and liquids-rich plays in the Eagle Ford Shale in Texas and the Mid-Continent region. During the quarter ended September 30, 2011, our Eagle Ford Shale production represented 17% of our total production. We had no Eagle Ford Shale production in 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 September 30,				Favorable			Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)
								($ per Mcfe)
Texas	$	43,380	$	18,718	$	24,662		$	8.84	$	4.65	$	4.19
Appalachia		9,517		11,796		(2,279	)		4.18		4.36		(0.18	)
Mid-Continent		21,992		28,244		(6,252	)		6.87		6.31		0.56
Mississippi		7,105		9,573		(2,468	)		4.55		4.61		(0.06	)
Total revenues	$	81,994	$	68,331	$	13,663		$	6.86	$	5.15	$	1.71

As illustrated below, oil and NGL production volume coupled with improved oil and NGL pricing were the significant factors for increasing revenues. The increase was partially offset by lower natural gas production volume and prices. The following table provides an analysis of the change in our revenues for the three months ended September 30, 2011 as compared to the three months ended September 30, 2010:

	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(12,374	)	$	(931	)	$	(13,305	)
Crude oil		16,895			6,856			23,751
NGL		453			2,764			3,217
	$	4,974		$	8,689		$	13,663

Effects of Derivatives

As part of our risk management strategy, we use derivative instruments to hedge against fluctuations in natural gas and oil prices. We received $5.6 million and $7.4 million in net cash settlements from commodity derivatives in the three months ended September 30, 2011 and 2010.

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

	Three Months Ended September 30,					Favorable
	2011		2010			(Unfavorable)			% Change
Natural gas revenues as reported	$	34,171	$	47,476		$	(13,305	)		(28	)%
Cash settlements on natural gas derivatives, net		5,075		7,497			(2,422	)		(32	)%
Natural gas revenues adjusted for derivatives	$	39,246	$	54,973		$	(15,727	)		(29	)%
Natural gas prices per Mcf, as reported	$	4.24	$	4.36		$	(0.12	)		(3	)%
Cash settlements on natural gas derivatives per Mcf		0.63		0.69			(0.06	)		(8	)%
Natural gas prices per Mcf adjusted for derivatives	$	4.87	$	5.05		$	(0.18	)		(4	)%
Crude oil revenues as reported	$	37,147	$	13,396		$	23,751			177	%
Cash settlements on crude oil derivatives, net		532		(65	)		597			918	%
Crude oil revenues adjusted for derivatives	$	37,679	$	13,331		$	24,348			183	%
Crude oil prices per Bbl, as reported	$	87.03	$	70.97		$	16.06			23	%
Cash settlements on crude oil derivatives per Bbl		1.25		(0.34	)		1.59			462	%
Crude oil prices per Bbl adjusted for derivatives	$	88.28	$	70.63		$	17.65			25	%

Gain on Sales of Property and Equipment

We recognized several individually insignificant gains on the sale of property, equipment, tubular inventory and well materials during both the 2011 and 2010 periods. The 2011 period includes an insignificant gain on the sale of a substantial portion of our Arkoma Basin assets in August 2011.

Other Income

During the quarter ended September 30, 2011, we received a settlement of $1.3 million from a partner attributable to oil and gas properties that we previously held in Appalachia.

Operating Expenses

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

	Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Lease operating	$	0.71	$	0.70	$	(0.01	)		(2	)%
Gathering, processing and transportation		0.25		0.27		0.02			9	%
Production and ad valorem taxes		0.28		0.40		0.12			29	%
General and administrative		1.06		1.01		(0.05	)		(5	)%
General and administrative excluding share-based compensation and restructuring charges		0.78		0.82		0.04			5	%
Depreciation, depletion and amortization		3.80		2.50		(1.30	)		(52	)%

Lease Operating

Lease operating expense decreased on an absolute basis in the 2011 period due primarily to the impact of lower overall production volumes as well as lower maintenance, compression and workover costs, partially offset by higher environmental, water disposal and employee-related costs. However, lease operating expenses increased marginally on a per unit basis during the 2011 period. A portion of the decline in volumes is attributable to the sale of our Arkoma Basin assets.

Gathering, Processing and Transportation

Gathering, processing and transportation charges decreased during the 2011 period due to overall lower production volumes, partially offset by higher processing costs associated with NGLs. The production of NGLs during the 2011 period represents a significantly larger proportion of the total production volume compared to the 2010 period.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased during the 2011 period due to a property tax recovery of $1.2 million attributable to wells in West Virginia as well as the effects of lower production volumes. As a percentage of product revenue, production and ad valorem taxes decreased to 4.1% during the 2011 period from 7.8% during the 2010 period.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:

	Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Recurring general and administrative expenses	$	9,262	$	10,947	$	1,685			15	%
Share-based compensation		1,820		1,711		(109	)		(6	)%
Restructuring expenses		1,553		787		(766	)		(97	)%
	$	12,635	$	13,445	$	810			6	%

Recurring general and administrative expenses decreased due to lower employee headcount and lower support costs resulting from restructuring actions taken during 2010. Share-based compensation charges increased during the 2011 period due primarily to a significant portion of the expense for the 2010 awards being accelerated in the first quarter as a result of retirement eligibility. Restructuring expenses during both the 2011 and 2010 periods includes termination benefits and office and employee relocation costs.

Exploration

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

	Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Dry hole costs	$	340	$	9,032	$	8,692		NM
Geological and geophysical costs		2,899		4,088		1,189			29	%
Unproved leasehold amortization		11,036		7,951		(3,085	)		(39	)%
Drilling rig charges		4,778		-		(4,778	)	NM
Other, primarily delay rentals		250		949		699			74	%
	$	19,303	$	22,020	$	2,717			12	%

The decrease in 2011 is due primarily to lower dry hole and geological and geophysical costs during the 2011 period partially offset by higher amortization of unproved leaseholds and rig-related charges that we incurred during the 2011 period in connection with the temporary suspension of our exploratory drilling program in the Marcellus Shale.

Depreciation, Depletion and Amortization (DD&A)

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

	Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Depletion	$	44,146	$	31,833	$	(12,313	)		(39	)%
Depreciation - Oil and gas operations		600		621		21			3	%
Depreciation - Corporate		494		659		165			25	%
Amortization		105		111		6			5	%
	$	45,345	$	33,224	$	(12,121	)		(36	)%

	DD&A Variance Due to
	Production		Rates			Total
Three months ended September 30, 2011 compared to 2010	$	3,336	$	(15,457	)	$	(12,121	)

Higher depletion during the 2011 period is due primarily to finding and development costs attributable to our Eagle Ford Shale oil wells. Our average depletion rate increased to $3.70 per Mcfe for the 2011 period from $2.40 per Mcfe for the 2010 period. The higher rate during the 2011 period reflects the continued shift toward liquids production.

Impairments

The following table summarizes the impairments recorded for the periods presented:

	Three Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)		% Change
Oil and gas properties	$	-	$	32,627	$	32,627	NM
Other		-		2,500		2,500	NM
	$	-	$	35,127	$	35,127	NM

During the 2010 period, we recognized 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. We also recorded impairment charges attributable to certain tubular inventory and well materials triggered primarily by declines in asset quality.

Other

During the 2011 period, we recorded a $0.3 million reserve for litigation attributable to properties that were previously sold.

Interest Expense

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

	Three Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Interest on borrowings and related fees	$	13,581		$	10,758		$	(2,823	)		(26	)%
Accretion of original issue discount		315			1,986			1,671			84	%
Amortization of debt issuance costs		747			883			136			15	%
Capitalized interest		(437	)		(438	)		(1	)		(0	)%
Other, net		-			9			9		NM
	$	14,206		$	13,198		$	(1,008	)		(8	)%

The issuance of the 2019 Senior Notes at 7.25% and borrowings under the Revolver, offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate at 8.5%, added approximately $108 million to the net principal amount of debt outstanding. Accordingly, interest expense increased due to higher average amounts of debt outstanding partially offset by lower effective interest rates.

Loss on Extinguishment of Debt

We recognized $1.2 million in August 2011 attributable to the issuance of the Revolver and a change in the composition of the bank syndicate.

Derivatives

The following table summarizes the components of our derivative income for the periods presented:

	Three Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Oil and gas derivative unrealized derivative gain	$	5,686		$	5,949		$	(263	)		(4	)%
Oil and gas derivative realized gain		5,607			7,433			(1,826	)		(25	)%
Interest rate swap unrealized gain (loss)		(2,715	)		2,361			(5,076	)	NM
Interest rate swap realized gain (loss)		2,920			(630	)		3,550		NM
	$	11,498		$	15,113		$	(3,615	)		(24	)%

We received cash settlements of $8.5 million during the three months ended September 30, 2011 and $6.8 million during the comparable period in 2010. The amount received during the 2011 period includes $2.9 million attributable to the termination of our interest rate swap.

Other

Other income decreased during the 2011 period due primarily to lower interest income earned on average cash balances.

Income Tax Expense

The effective tax rate for the three months ended September 30, 2011 was 47.7% compared to 40.6% for the 2010 period. Due to operating losses incurred during the 2011 period, we recognized an income tax benefit. In addition, the effective tax rate for the 2011 period includes a deferred tax asset valuation allowance due primarily to the inability to recognize a tax benefit for certain state net operating losses.

Nine Months Ended September 30, 2011 Compared to the Nine Months Ended September 30, 2010

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

	Nine Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Total Production:
Natural gas (MMcf)		26,646			28,590			(1,944	)		(7	)%
Crude oil (MBbl)		833			522			311			60	%
NGL (MBbl)		695			395			300			76	%
Total production (MMcfe)		35,817			34,093			1,724			5	%

Realized prices, before derivatives:
Natural gas ($/Mcf)	$	4.27		$	4.70		$	(0.43	)		(9	)%
Crude oil ($/Bbl)		90.33			72.96			17.37			24	%
NGL ($/Bbl)		48.56			37.96			10.60			28	%
Total ($/Mcfe)	$	6.22		$	5.50		$	0.72			13	%

Revenues
Natural gas	$	113,660		$	134,283		$	(20,623	)		(15	)%
Crude oil		75,278			38,117			37,161			97	%
NGL		33,758			14,987			18,771			125	%
Total product revenues		222,696			187,387			35,309			19	%
Gain on sales of property and equipment		523			616			(93	)		(15	)%
Other income		2,335			2,116			219			10	%
Total revenues		225,554			190,119			35,435			19	%

Operating Expenses
Lease operating		29,522			27,148			(2,374	)		(9	)%
Gathering, processing and transportation		11,261			10,165			(1,096	)		(11	)%
Production and ad valorem taxes		11,289			12,684			1,395			11	%
General and administrative		38,941			44,297			5,356			12	%
Exploration		68,219			37,590			(30,629	)		(81	)%
Depreciation, depletion and amortization		113,224			95,358			(17,866	)		(19	)%
Impairments		71,071			36,251			(34,820	)		(96	)%
Other		300			465			165			35	%
Total operating expenses		343,827			263,958			(79,869	)		(30	)%

Operating loss		(118,273	)		(73,839	)		(44,434	)		(60	)%
Other income (expense)
Interest expense		(41,833	)		(40,190	)		(1,643	)		(4	)%
Loss on extinguishment of debt		(25,403	)		-			(25,403	)	NM
Derivatives		19,827			44,410			(24,583	)		(55	)%
Other		334			2,105			(1,771	)		(84	)%
Loss from continuing operations before income taxes		(165,348	)		(67,514	)		(97,834	)		(145	)%
Income tax benefit		60,372			27,024			33,348			123	%
Loss from continuing operations		(104,976	)		(40,490	)		(64,486	)		(159	)%
Income from discontinued operations, net of tax		-			33,482			(33,482	)	NM
Gain on sale of discontinued operations		-			49,612			(49,612	)	NM
Net income (loss)		(104,976	)		42,604			(147,580	)	NM
Less net income attributable to noncontrolling interests		-			(28,090	)		28,090		NM
Income (loss) attributable to Penn Virginia Corporation	$	(104,976	)	$	14,514		$	(119,490	)	NM

NM - Not meaningful

Production

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

	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)			% Change
	(MMcfe)							(MMcfe per day)
Texas		12,958		9,225		3,733			47.5		33.8		13.7			40	%
Appalachia		6,892		7,891		(999	)		25.2		28.9		(3.7	)		(13	)%
Mid-Continent		10,850		11,188		(338	)		39.8		41.0		(1.2	)		(3	)%
Mississippi		5,117		5,494		(377	)		18.7		20.1		(1.4	)		(7	)%
Gulf Coast (Divested)		-		295		(295	)		-		1.1		(1.1	)		(100	)%
Total production		35,817		34,093		1,724			131.2		124.9		6.3			5	%

The increase in total production was due primarily to the increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. The increase in oil and NGL production was partially offset by a decline in natural gas production attributable to the lack of any significant natural gas drilling since mid-2010 and the subsequent natural production declines. Approximately 26% of total production on an equivalent basis in the nine months ended September 30, 2011 was attributable to oil and NGLs, an increase of 67% compared to the corresponding period in 2010. The shift in production mix reflects our focus on emerging oil and liquids-rich plays in the Eagle Ford Shale in Texas and the Mid-Continent region. Oil and NGL production comprised over 41% and 35% of our total production in Texas and the Mid-Continent regions, respectively, through the first nine months of 2011. Our Eagle Ford Shale production was initiated during the first quarter of 2011 and continues to grow and represent an increasingly significant component of our total production. We anticipate that this shift in production mix will continue.

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:

	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			2011		2010		(Unfavorable)
								($ per Mcfe)
Texas	$	95,306	$	47,125	$	48,181		$	7.35	$	5.11	$	2.24
Appalachia		29,106		36,404		(7,298	)		4.22		4.61		(0.39	)
Mid-Continent		74,891		75,326		(435	)		6.90		6.73		0.17
Mississippi		23,393		26,356		(2,963	)		4.57		4.80		(0.23	)
Gulf Coast (Divested)		-		2,176		(2,176	)		-		7.38		(7.38	)
Total revenues	$	222,696	$	187,387	$	35,309		$	6.22	$	5.50	$	0.72

As illustrated below, oil and NGL production volume coupled with improved oil and NGL pricing were the significant factors for increasing revenues. The increase was partially offset by lower natural gas production volumes and prices. The following table provides an analysis of the change in our revenues for the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010:

	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(9,131	)	$	(11,492	)	$	(20,623	)
Crude oil		22,685			14,476			37,161
NGL		11,404			7,367			18,771
	$	24,958		$	10,351		$	35,309

Effects of Derivatives

As part of our risk management strategy, we use derivative instruments to hedge against fluctuations in natural gas and oil prices. We received $16.5 million and $25.3 million in cash settlements from commodity derivatives in the nine months ended September 30, 2011 and 2010.

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

	Nine Months Ended September 30,					Favorable
	2011		2010			(Unfavorable)			% Change
Natural gas revenues as reported	$	113,660	$	134,283		$	(20,623	)		(15	)%
Cash settlements on natural gas derivatives, net		16,305		25,424			(9,119	)		(36	)%
Natural gas revenues adjusted for derivatives	$	129,965	$	159,707		$	(29,742	)		(19	)%

Natural gas prices per Mcf, as reported	$	4.27	$	4.70		$	(0.43	)		(9	)%
Cash settlements on natural gas derivatives per Mcf		0.61		0.89			(0.28	)		(31	)%
Natural gas prices per Mcf adjusted for derivatives	$	4.88	$	5.59		$	(0.71	)		(13	)%

Crude oil revenues as reported	$	75,278	$	38,117		$	37,161			97	%
Cash settlements on crude oil derivatives, net		179		(167	)		346			207	%
Crude oil revenues adjusted for derivatives	$	75,457	$	37,950		$	37,507			99	%

Crude oil prices per Bbl, as reported	$	90.33	$	72.96		$	17.37			24	%
Cash settlements on crude oil derivatives per Bbl		0.21		(0.32	)		0.53			167	%
Crude oil prices per Bbl adjusted for derivatives	$	90.54	$	72.64		$	17.90			25	%

Gain on Sales of Property and Equipment

Other Income

During the quarter ended September 30, 2011, we received a settlement of $1.3 million from a partner attributable to oil and gas properties that we previously held in Appalachia.

Operating Expenses

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

	Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Lease operating	$	0.82	$	0.80	$	(0.02	)		(3	)%
Gathering, processing and transportation		0.31		0.30		(0.01	)		(5	)%
Production and ad valorem taxes		0.32		0.37		0.05			15	%
General and administrative		1.09		1.30		0.21			16	%
General and administrative excluding share-based
compensation and restructuring charges		0.88		0.92		0.04			4	%
Depreciation, depletion and amortization		3.16		2.80		(0.36	)		(13	)%

Lease Operating

Lease operating expense increased on an absolute basis in the 2011 period due to higher employee-related costs as well as higher maintenance and workover costs. In addition, certain other costs, including water disposal, were generally higher commensurate with higher production volumes during the 2011 period.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during the 2011 period due to overall higher production volumes as well as higher processing costs associated with NGLs. The production of NGLs during the 2011 period represents a significantly larger proportion of the total production volume compared to the 2010 period.

Production and Ad Valorem Taxes

Production and ad valorem taxes were lower despite higher production volumes during the 2011 period due primarily to a property tax recovery of $1.2 million in the 2011 period attributable to wells located in West Virginia. As a percentage of product revenue, production and ad valorem taxes decreased to 5.1% during the 2011 period from 6.8% during the 2010 period.

General and Administrative

The following table sets forth the components of general and administrative expenses for the periods presented:

	Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Recurring general and administrative expenses	$	31,689	$	31,463	$	(226	)		(1	)%
Share-based compensation		5,629		6,400		771			12	%
Restructuring expenses		1,623		6,434		4,811			75	%
	$	38,941	$	44,297	$	5,356			12	%

Recurring general and administrative expenses increased marginally during the 2011 period as compared to the 2010 period. Higher employee benefits costs and other corporate costs were offset by lower salaries and wages and occupancy costs, as well as lower professional fees and consulting charges. Share-based compensation charges decreased during the 2011 period due primarily to a smaller number of awards that vested upon grant due to retirement eligibility. Restructuring expenses during the 2011 period include termination benefits and office and employee relocation costs attributable to the restructuring following the sale of our Arkoma Basin properties. Restructuring expenses during the 2010 period include termination benefits and office and employee relocation costs as well as a $3.5 million charge related to the assignment of the lease of our former Kingsport, Tennessee office facility.

Exploration

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

	Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Dry hole costs	$	18,864	$	9,059	$	(9,805	)		(108	)%
Geological and geophysical costs		9,036		8,573		(463	)		(5	)%
Unproved leasehold amortization		33,593		17,442		(16,151	)		(93	)%
Drilling rig charges		4,778		-		(4,778	)	NM
Other, primarily delay rentals		1,948		2,516		568			23	%
	$	68,219	$	37,590	$	(30,629	)		(81	)%

The increase in dry hole costs is attributable primarily to four unsuccessful wells in the Mid-Continent region during the 2011 period as compared to one during the 2010 period in the same region. Geological and geophysical costs reflect a larger exploration program in the 2011 period compared to the 2010 period. The increase in amortization of unproved leaseholds is due primarily to significant acquisitions during 2010. In addition, we incurred rig-related charges during the 2011 period in connection with the temporary suspension of our exploratory drilling program in the Marcellus Shale.

Depreciation, Depletion and Amortization (DD&A)

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

	Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Depletion	$	109,195	$	90,377	$	(18,818	)		(21	)%
Depreciation - Oil and gas operations		1,837		1,913		76			4	%
Depreciation - Corporate		1,825		2,736		911			33	%
Amortization		367		332		(35	)		(11	)%
	$	113,224	$	95,358	$	(17,866	)		(19	)%

	DD&A Variance Due to
	Production			Rates			Total
Nine months ended September 30, 2011 compared to 2010	$	(4,822	)	$	(13,044	)	$	(17,866	)

Higher depletion during the 2011 period is commensurate with higher production volumes and the effect of finding and development costs attributable primarily to our oil wells in the Eagle Ford Shale play. Our average depletion rate increased to $3.05 per Mcfe for the 2011 period from $2.65 per Mcfe for the 2010 period. The higher rate during the 2011 period reflects the continued shift toward liquids production.

Impairments

The following table summarizes the impairments recorded for the periods presented:

	Nine Months Ended September 30,				Favorable
	2011		2010		(Unfavorable)			% Change
Oil and gas properties	$	71,071	$	32,627	$	(38,444	)	NM
Other		-		3,624		3,624		NM
	$	71,071	$	36,251	$	(34,820	)	NM

During the quarter ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties. The sale was completed in August 2011. During the prior year period, we recognized 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. We also recorded impairment charges attributable to certain tubular inventory and well materials triggered primarily by declines in asset quality.

Other

During the 2011 period, we recorded a $0.3 million reserve for litigation attributable to properties that were previously sold. During the 2010 period, we recorded a loss on the disposition of our Gulf Coast properties.

Interest Expense

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

	Nine Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Interest on borrowings and related fees	$	37,448		$	32,245		$	(5,203	)		(16	)%
Accretion of original issue discount		3,103			6,097			2,994			49	%
Amortization of debt issuance costs		2,709			2,992			283			9	%
Capitalized interest		(1,427	)		(1,155	)		272			24	%
Other, net		-			11			11			100	%
	$	41,833		$	40,190		$	(1,643	)		(4	)%

Loss on Extinguishment of Debt

The repurchase in April 2011 of approximately 98% of the outstanding Convertible Notes resulted in a loss on extinguishment of debt of $24.2 million. The loss was comprised of non-cash charges for the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of incremental transaction costs and fees paid in cash. In addition, we recognized a charge of $1.2 million in August 2011 attributable to the issuance of the Revolver and a change in the composition of the bank syndicate.

Derivatives

The following table summarizes the components of our derivative income for the periods presented:

	Nine Months Ended September 30,						Favorable
	2011			2010			(Unfavorable)			% Change
Oil and gas derivative unrealized derivative gain	$	2,114		$	13,476		$	(11,362	)		(84	)%
Oil and gas derivative realized gain		16,484			25,258			(8,774	)		(35	)%
Interest rate swap unrealized gain (loss)		(2,589	)		6,646			(9,235	)		(139	)%
Interest rate swap realized gain (loss)		3,818			(970	)		4,788			494	%
	$	19,827		$	44,410		$	(24,583	)		(55	)%

We received cash settlements of $20.3 million during the nine months ended September 30, 2011 and $24.3 million during the comparable period in 2010. The amount received during the 2011 period includes $2.9 million attributable to the termination of our interest rate swap.

Other

Other income decreased due primarily to lower interest income earned on average cash balances during the 2011 period and gains on the sale of non-operating investments recognized during the 2010 period.

Income Tax Expense

The effective tax rate for the nine months ended September 30, 2011 was 36.5% compared to 40.0% for the 2010 period. Due to operating losses incurred during the 2011 period, we recognized an income tax benefit. In addition, the effective tax rate for the 2011 period includes a deferred tax asset valuation allowance due primarily to the inability to recognize a tax benefit for certain state net operating losses.

Discontinued Operations

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

	Nine Months Ended September 30,
	2011		2010
Revenues	$	-	$	303,206

Income from discontinued operations before taxes	$	-	$	36,832
Income tax expense 1		-		(3,350	)
	$	-	$	33,482

1	Determined by applying the effective tax rate attributable to discontinued operations to the income from discontinued operations less noncontrolling interests that are fully attributable to the operations of Penn Virginia GP Holdings, L.P., or PVG.

Gain on Sale of Discontinued Operations

In June 2010, we completed the sale of all of our remaining interest in PVG for $139.1 million net of offering costs and contributed 100% of the membership interests in PVG’s general partner to PVG thereby relinquishing control of PVG. As a result of this divestiture, we recognized a gain of $49.6 million, net of income tax effects of $35.1 million. Final sale adjustments were recorded during the fourth quarter of 2010.

Liquidity and Capital Resources

Sources of Liquidity

We are currently meeting our capital expenditures and working capital funding requirements with a combination of operating cash flows and borrowings from our Revolver. Our business strategy for the remainder of 2011 includes capital expenditures in excess of our anticipated operating cash flows. Subject to the variability of commodity prices that impact our operating cash flows, anticipated timing of our capital projects and unanticipated expenditures, such as acquisitions, we plan to fund our remaining 2011 capital program with operating cash flows, proceeds from non-core asset sales and borrowings from our Revolver.

In August 2011, we entered into the Revolver which matures in August 2016. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has a borrowing base of $380 million, which has been adjusted to reflect the sale of our Arkoma Basin assets. The borrowing base is redetermined semi-annually. There is an accordion feature that allows us to increase the commitment up to the lower of the borrowing base or $600 million upon receiving additional commitments from one or more lenders. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions.

As of September 30, 2011, we had $3.6 million of cash on hand and approximately $284 million of unused borrowing capacity under our Revolver. The borrowing capacity is determined by reducing the revolving commitment of $300 million by outstanding borrowings of $15 million and outstanding letters of credit of $1.4 million.

The following table summarizes our borrowing activity under the Revolver during the period presented:

	Borrowings Outstanding
	Weighted-				Weighted-
	Average		Maximum		Average Rate
Three months ended September 30, 20111	$	12,500	$	30,000		1.80	%

1	There were no amounts outstanding under the previous credit facility from January 1, 2011 through its termination date of August 2, 2011.

We actively manage the exposure of our operating cash flows to commodity price fluctuations by hedging the commodity price risk for a portion of our expected production through the use of derivatives, typically costless collar and swap contracts. The level of our hedging activity and duration of the instruments employed depend upon our cash flow at risk, available hedge prices and our operating strategy. During the nine months ended September 30, 2011, our commodity derivatives portfolio provided $16.3 million of cash inflows to offset lower than anticipated prices received for our current year natural gas production and $0.2 million of cash inflows attributable to lower than anticipated prices received for our current year crude oil production. For the remainder of 2011, we have hedged approximately 38% of our estimated natural gas production, at a weighted average floor/swap price of $5.67 per MMBtu. In addition, we have hedged approximately 11% of our estimated crude oil production for the remainder of 2011, at weighted average floor/swap and ceiling prices of between $96.86 and $106.61 per barrel.

Cash Flows

The following table summarizes our statements of cash flows for the periods presented:

	Nine Months Ended September 30,
	2011			2010			Variance
Cash flows from operating activities	$	103,164		$	68,875		$	34,289
Cash flows from investing activities
Capital expenditures - property and equipment		(318,274	)		(313,710	)		(4,564	)
Proceeds from the sale of PVG units, net		-			139,120			(139,120	)
Proceeds from sales of property and equipment and other, net		31,177			26,364			4,813
Net cash used in investing activities		(287,097	)		(148,226	)		(138,871	)
Cash flows from financing activities
Dividends paid		(7,736	)		(7,700	)		(36	)
Proceeds from revolving credit facility borrowings		30,000			-			30,000
Repayment of revolving credit facility borrowings		(15,000	)		-			(15,000	)
Proceeds from issuance of Senior Notes due 2019		300,000			-			300,000
Repurchase of Convertible Notes		(232,963	)		-			(232,963	)
Debt issuance costs paid		(8,850	)		-			(8,850	)
Proceeds from sale of PVG units, net		-			199,125			(199,125	)
Distributions received from discontinued operations		-			11,218			(11,218	)
Other, net		1,148			2,143			(995	)
Net cash provided by financing activities		66,599			204,786			(138,187	)
Net increase (decrease) in cash and cash equivalents	$	(117,334	)	$	125,435		$	(242,769	)

Cash Flows From Operating Activities

The following table summarizes the most significant variances in our cash flows from operating activities:

Cash flows from operating activities for the nine months ended September 30, 2010	$	68,875
Variances due to:
Lower settlements from commodity derivatives portfolio		(8,774	)
Lower interest payments, net of amounts capitalized		5,358
Lower restructuring costs paid		6,543
Lower tax payments		24,735
Transaction costs paid in connection with extinguishment of debt		(2,433	)
Effect of higher operating margins, net of working capital changes		8,860
Cash flows from operating activities for the nine months ended September 30, 2011	$	103,164

Cash Flows From Investing Activities

Cash used in investing activities was $287.1 million in the nine months ended September 30, 2011 compared to $148.2 million in the corresponding period in 2010. While capital expenditures, net of property sales, were approximately the same in both periods, the 2010 period expenditures were reduced by $139.1 million of proceeds from the sale of our remaining interests in PVG.

The following table sets forth costs related to our capital expenditures programs for the periods presented:

	Nine Months Ended September 30,
	2011		2010
Oil and gas:
Development drilling	$	207,887	$	190,573
Exploration drilling		53,247		21,063
Seismic		9,036		8,573
Lease acquisitions, field projects and other		46,393		120,329
Pipeline and gathering facilities		6,273		887
		322,836		341,425
Other - Corporate		1,163		1,185
Total capital program costs	$	323,999	$	342,610

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,
	2011			2010
Total capital program costs	$	323,999		$	342,610
Less:
Exploration expenses
Seismic		(9,036	)		(8,573	)
Other, primarily delay rentals		(1,948	)		(2,213	)
Other		(1,954	)		-
Changes in accrued capitalized costs		5,686			(11,065	)
Property received as consideration in sale transaction 1		-			(8,204	)
Add:
Capitalized interest		1,427			1,155
Other		100			-
Total cash paid for capital expenditures	$	318,274		$	313,710

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

Cash Flows From Financing Activities

Cash provided by financing activities during the 2011 period includes the issuance of $300 million of 2019 Senior Notes, offset substantially by the repurchase of approximately 98% of our Convertible Notes and related transaction costs. During the third quarter of 2011, we began borrowing on our Revolver. In addition, we paid dividends of $7.7 million on our common stock.

During the 2010 period, we sold 11.25 million common units of PVG for proceeds of $199.1 million, net of offering costs, which reduced our limited partner interest in PVG to 22.6% at that time. Because we maintained a controlling financial interest in PVG until the final sale in June 2010, the proceeds from this transaction were reported as cash flows from financing activities. In addition, in the 2010 period, we received $11.2 million in distributions from PVG.

Financial Condition

As of September 30, 2011, we had $3.6 million of cash on hand and approximately $284 million of unused borrowing capacity under our Revolver.

Credit Facility and Debt

The following table summarizes the components our long-term debt as of the periods presented:

	September 30,		December 31,
	2011		2010
Revolving credit facility	$	15,000	$	-
Senior Notes due 2016, net of discount (principal amount of $300,000)		293,281		292,487
Senior Notes due 2019		300,000		-
Convertible Notes due 2012, net of discount (principal amount of $4,915 and $230,000)		4,702		214,049
	$	612,983	$	506,536

Revolving Credit Facility. Borrowings under the Revolver bear interest, at our option, at either (i) a rate derived from the London Interbank Offered Rate, as adjusted for statutory reserve requirements for Eurocurrency liabilities, or Adjusted LIBOR, plus an applicable margin ranging from 1.500% to 2.500% or (ii) the greater of (a) the prime rate, (b) the federal funds effective rate plus 0.5% or (c) the one-month Adjusted LIBOR plus 1.0%, and, in each case, plus an applicable margin (ranging from 0.500% to 1.500%). In each case, the applicable margin is determined based on the ratio of our outstanding borrowings to the available Revolver capacity. Commitment fees are being charged at 0.375% increasing to 0.500% on the undrawn portion of the Revolver as determined by our ratio of outstanding borrowings to the available Revolver capacity.

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

2016 Senior Notes. The Senior Notes due 2016, or 2016 Senior Notes, bear interest at an annual rate of 10.375% payable on June 15 and December 15 of each year. The 2016 Senior Notes were sold at 97% of par, equating to an effective yield to maturity of approximately 11%. The 2016 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2016 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Under the Revolver, we are permitted under certain conditions to repurchase up to $100 million of the 2016 Senior Notes until August 2012. Accordingly, we may, from time to time, seek to repurchase the 2016 Senior Notes through open market purchases or privately negotiated transactions. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

2019 Senior Notes. The 2019 Senior Notes, which were issued at par in April 2011, bear interest at an annual rate of 7.25% payable on April 15 and October 15 of each year. The 2019 Senior Notes are senior to our existing and future subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including the Revolver, to the extent of the collateral securing that indebtedness. The obligations under the 2019 Senior Notes are fully and unconditionally guaranteed by the Guarantor Subsidiaries.

Convertible Notes. The Convertible Notes, which mature in November 2012, are convertible into cash up to the principal amount thereof and shares of our common stock, if any, in respect of the excess conversion value, based on an initial conversion rate of 17.3160 shares of common stock per $1,000 principal amount of the Convertible Notes (which is equal to an initial conversion price of approximately $57.75 per share of common stock), subject to adjustment. The Convertible Notes bear interest at an annual rate of 4.50% payable semi-annually in arrears on May 15 and November 15 of each year.

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

In connection with a tender offer completed in April 2011, the Company repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million reflecting a premium of $35 per $1,000 principal amount. The tender offer resulted in the extinguishment of approximately 98% of the outstanding Convertible Notes. The tender offer was funded with the net proceeds of the 2019 Senior Notes. Subsequent to the tender offer, a total of $4.9 million aggregate principal amount of Convertible Notes remain outstanding. The remaining unamortized discount will be amortized through November 2012.

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

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

Covenant Compliance

Our Revolver requires 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 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.

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

As of September 30, 2011 and through the date upon which the Condensed Consolidated Financial Statements were issued, we were in compliance with these financial covenants.

The following table summarizes the actual results of our financial covenant compliance under the Revolver for the period ended September 30, 2011:

	Required	Actual
Description of Covenant	Covenant	Results
Total debt to EBITDAX	< 4.5 to 1	3.0 to 1
Current ratio	> 1.0 to 1	3.5 to 1

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

Future Capital Needs and Commitments

In 2011, we anticipate making capital expenditures, excluding any additional acquisitions, of approximately $438 million. The capital expenditures have been and will continue to be funded primarily by operating cash flows and, as necessary, proceeds from non-core asset sales and borrowing under the Revolver. We continually review drilling and other capital expenditure plans and may change the amount we spend in any area based on available opportunities, industry conditions, cash flows provided by operating activities and the availability of capital.

Based on expenditures to date and forecasted activity for the remainder of 2011, we expect to allocate the capital expenditures as follows: Eagle Ford Shale (66%), Marcellus Shale (9%), Mid-Continent region (20%) and all other areas (5%). This allocation includes approximately 84% for development and exploratory drilling, 11% for leasehold acquisition and 5% for seismic and other projects. We anticipate that we will allocate approximately 83% of capital expenditures to oil and NGL projects.

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations including the plugging of abandoned wells. As of September 30, 2011, we have outstanding asset retirement obligations of approximately $6.0 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. See Item 1A Risk Factors.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010 and remained unchanged as of September 30, 2011.

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 interest rate risk and commodity price risk. Our interest rate risk is attributable to our borrowings under the Revolver at variable interest rates. A change in interest rates of one percent on our outstanding Revolver borrowings as of September 30, 2011 would result in a change in interest expense of approximately $0.2 million on an annual basis.

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

In the nine months ended September 30, 2011, we reported net commodity derivative gains of $18.6 million. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our derivative instruments. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment. See Note 5 to the Condensed Consolidated Financial Statements for a further description of our price risk management activities.

The following table lists our commodity derivative positions and their fair values as of September 30, 2011:

		Average
		Volume Per		Weighted Average Price				Fair Value
	Instrument	Day		Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)		($/MMBtu)
Fourth quarter 2011	Costless collars		20,000	$	6.00	$	8.50	$	4,047	$	-
First quarter 2012	Costless collars		20,000	$	6.00	$	8.50		3,405		-
Fourth quarter 2011	Swaps		10,000	$	5.01				1,114		-
First quarter 2012	Swaps		10,000	$	5.10				881		-
Second quarter 2012	Swaps		20,000	$	5.31				2,117		-
Third quarter 2012	Swaps		20,000	$	5.31				1,952		-
Fourth quarter 2012	Swaps		10,000	$	5.10				557		-

Crude Oil:		(barrels)		($/barrel)
Fourth quarter 2011	Costless collars		360	$	80.00	$	103.30		168		-
First quarter 2012	Costless collars		500	$	100.00	$	120.00		983		-
Second quarter 2012	Costless collars		500	$	100.00	$	120.00		986		-
Third quarter 2012	Costless collars		500	$	100.00	$	120.00		974		-
Fourth quarter 2012	Costless collars		500	$	100.00	$	120.00		951		-
Fourth quarter 2011	Swaps		500	$	109.00				1,709		-
								$	19,844	$	-

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

	Change of $1.00 per MMBtu of Natural Gas
	or $10.00 per Barrel of Crude Oil
	($ in millions)
	Increase			Decrease
Effect on the fair value of natural gas derivatives	$	(8.8	)	$	9.2
Effect on the fair value of crude oil derivatives	$	(2.2	)	$	1.9
Effect on 2011 operating income, excluding natural gas derivatives	$	7.3		$	(7.3	)
Effect on 2011 operating income, excluding crude oil derivatives	$	7.6		$	(7.6	)

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, 2011. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2011, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1A Risk Factors

Federal and state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

The practice of hydraulic fracturing has come under increased scrutiny by the environmental community. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into prospective rock formations to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells. The U.S. Environmental Protection Agency has commenced a study of the potential environmental impact of hydraulic fracturing, with initial results of the study anticipated to be available by late 2012. Also, the Secretary of Energy Advisory Board has established a Natural Gas Subcommittee to make recommendations on improving safety and environmental performance of hydraulic fracturing. The subcommittee issued a draft report in August 2011 with the final report due in November. The House of Representatives Committee on Science, Space, and Technology held a hearing in May, 2011 on hydraulic fracturing technology and practices and other committees are expected to continue to take up various aspects of hydraulic fracturing through the remainder of the 112th Congress. In addition, some states have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing operations. Individually or collectively, such new legislation or regulation could result in increased compliance and operating costs or additional operating restrictions. If the use of hydraulic fracturing is limited or prohibited, it could delay or effectively prevent the extraction of oil and gas from formations which would not be economically viable without the use of hydraulic fracturing. This could have a material adverse effect on our business, financial condition and results of operations.

Item 6 Exhibits

2.1	Purchase and Sale Agreement, dated July 28, 2011, by and among Penn Virginia MC Energy L.L.C., Penn Virginia Oil & Gas Corporation and Unit Petroleum Company, as amended by Amendment and Supplement to Purchase and Sale Agreement dated August 31, 2011 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on September 7, 2011).

10.1	Amended and Restated Credit Agreement dated as of August 2, 2011 among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 4, 2011).

10.2	Partial Unwind Agreement dated as of August 5, 2011 between Penn Virginia Corporation and JPMorgan Chase Bank, National Association, London Branch (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 10, 2011).

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

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

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

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

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

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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

		PENN VIRGINIA CORPORATION

Date:	November 3, 2011	By:	/s/ Steven A. Hartman
			Steven A. Hartman
			Senior Vice President and Chief Financial Officer

Date:	November 3, 2011	By:	/s/ Joan C. Sonnen
			Joan C. Sonnen
			Vice President and Controller