BAYTEX ENERGY USA, INC. - Quarter Report: 2012 September (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

____________________________________________________________________________

FORM 10-Q

____________________________________________________________________________

(Mark One)



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

For the quarterly period ended September 30, 2012



¨	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 26, 2012, 55,093,146 shares of common stock of the registrant were outstanding.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2012

Table of Contents



Item		Page
	Part I - Financial Information

1.	Financial Statements:
	Condensed Consolidated Statements of Operations for the Periods Ended September 30, 2012 and 2011	1
	Condensed Consolidated Statements of Comprehensive Income for the Periods Ended September 30, 2012 and 2011	2
	Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	3
	Condensed Consolidated Statements of Cash Flows for the Periods Ended September 30, 2012 and 2011	4
	Notes to Condensed Consolidated Financial Statements:
	1. Organization	5
	2. Basis of Presentation	5
	3. Acquisitions and Divestitures	5
	4. Accounts Receivable and Major Customers	6
	5. Derivative Instruments	6
	6. Property and Equipment	9
	7. Long-Term Debt	9
	8. Additional Balance Sheet Detail	12
	9. Fair Value Measurements	12
	10. Commitments and Contingencies	14
	11. Shareholders’ Equity	15
	12. Share-Based Compensation	15
	13. Restructuring and Exit Activities	16
	14. Impairments	17
	15. Interest Expense	17
	16. Earnings per Share	18
Forward-Looking Statements		19
2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations:	20
	Overview of Business	20
	Key Developments	21
	Results of Operations	22
	Liquidity and Capital Resources	39
	Environmental Matters	44
	Critical Accounting Estimates	44
	New Accounting Standards	45
3.	Quantitative and Qualitative Disclosures About Market Risk	46
4.	Controls and Procedures	48
	Part II - Other Information
6.	Exhibits	49
Signatures		51

Table of Contents

PART I. FINANCIAL INFORMATION


Item 1.	Financial Statements

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS – unaudited

(in thousands, except per share data)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Revenues
Natural gas	$	11,909		$	34,171		$	37,098		$	113,660
Crude oil	56,995			37,147			174,100			75,278
Natural gas liquids (NGLs)	6,671			10,676			23,298			33,758
Gain on sales of property and equipment, net	1,573			71			2,407			523
Other	551			1,288			2,052			2,335
Total revenues	77,699			83,353			238,955			225,554
Operating expenses
Lease operating	6,206			8,458			24,613			29,522
Gathering, processing and transportation	3,127			2,952			11,672			11,261
Production and ad valorem taxes	4,589			3,391			7,915			11,289
General and administrative	11,634			12,635			35,522			38,941
Exploration	9,265			19,303			26,647			68,219
Depreciation, depletion and amortization	49,331			45,345			151,888			113,224
Impairments	700			—			29,316			71,071
Loss on firm transportation commitment	17,332			—			17,332			—
Other	—			300			—			300
Total operating expenses	102,184			92,384			304,905			343,827
Operating loss	(24,485		)	(9,031		)	(65,950		)	(118,273		)
Other income (expense)
Interest expense	(14,979		)	(14,206		)	(44,837		)	(41,833		)
Loss on extinguishment of debt	(3,144		)	(1,165		)	(3,144		)	(25,403		)
Derivatives	(12,271		)	11,498			31,250			19,827
Other	60			61			89			334
Loss before income taxes	(54,819		)	(12,843		)	(82,592		)	(165,348		)
Income tax benefit	22,208			6,125			32,444			60,372
Net loss	$	(32,611	)	$	(6,718	)	$	(50,148	)	$	(104,976	)
Loss per share:
Basic	$	(0.71	)	$	(0.15	)	$	(1.09	)	$	(2.29	)
Diluted	$	(0.71	)	$	(0.15	)	$	(1.09	)	$	(2.29	)
Weighted average shares outstanding, basic	46,050			45,817			46,009			45,758
Weighted average shares outstanding, diluted	46,050			45,817			46,009			45,758

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

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME – unaudited

(in thousands)



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net loss	$	(32,611	)	$	(6,718	)	$	(50,148	)	$	(104,976	)
Other comprehensive income:
Change in pension and postretirement obligations, net of tax of $11 and $37 in 2012 and $19 and $55 in 2011	23			34			69			102
	23			34			69			102
Comprehensive loss	$	(32,588	)	$	(6,684	)	$	(50,079	)	$	(104,874	)

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

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands, except share data)



	As of
	September 30, 2012			December 31, 2011
Assets
Current assets
Cash and cash equivalents	$	5,033		$	7,512
Accounts receivable, net of allowance for doubtful accounts	70,039			72,432
Derivative assets	11,252			18,987
Income taxes receivable	—			31,465
Other current assets	5,583			14,950
Total current assets	91,907			145,346
Property and equipment, net (successful efforts method)	1,745,091			1,777,575
Derivative assets	6,892			—
Other assets	18,847			20,132
Total assets	$	1,862,737		$	1,943,053
Liabilities and Shareholders’ Equity
Current liabilities
Accounts payable and accrued liabilities	$	112,021		$	94,504
Derivative liabilities	817			3,549
Deferred income taxes	3,807			3,808
Income taxes payable	22			—
Current portion of long-term debt	4,884			4,746
Total current liabilities	121,551			106,607
Other liabilities	29,258			15,887
Derivative liabilities	1,677			6,850
Deferred income taxes	243,522			274,839
Long-term debt	671,447			692,561
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 45,893,146 and 45,714,191 as of September 30, 2012 and December 31, 2011, respectively	271			270
Paid-in capital	694,359			690,131
Retained earnings	101,918			157,242
Deferred compensation obligation	3,072			3,620
Accumulated other comprehensive loss	(1,015		)	(1,084		)
Treasury stock – 209,392 and 223,886 shares of common stock, at cost, as of September 30, 2012 and December 31, 2011, respectively	(3,323		)	(3,870		)
Total shareholders’ equity	795,282			846,309
Total liabilities and shareholders’ equity	$	1,862,737		$	1,943,053

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

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)



	Nine Months Ended September 30,
	2012			2011
Cash flows from operating activities
Net loss	$	(50,148	)	$	(104,976	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Non-cash portion of loss on extinguishment of debt	3,144			22,456
Loss on firm transportation commitment	17,332			—
Depreciation, depletion and amortization	151,888			113,224
Impairments	29,316			71,071
Derivative contracts:
Net gains	(31,250		)	(19,827		)
Cash settlements	24,189			20,302
Deferred income tax benefit	(32,444		)	(60,372		)
Gain on sales of assets, net	(2,407		)	(223		)
Non-cash exploration expense	24,765			52,457
Non-cash interest expense	3,107			5,812
Share-based compensation (equity-classified)	4,233			5,629
Other, net	302			225
Changes in operating assets and liabilities, net	48,187			(2,614		)
Net cash provided by operating activities	190,214			103,164
Cash flows from investing activities
Capital expenditures - property and equipment	(257,194		)	(318,274		)
Proceeds from sales of assets, net	93,276			31,077
Other, net	180			100
Net cash used in investing activities	(163,738		)	(287,097		)
Cash flows from financing activities
Dividends paid	(5,176		)	(7,736		)
Proceeds from revolving credit facility borrowings	181,000			30,000
Repayment of revolving credit facility borrowings	(203,000		)	(15,000		)
Proceeds from the issuance of senior notes	—			300,000
Repurchase of convertible notes	—			(232,963		)
Debt issuance costs paid	(1,779		)	(8,850		)
Other, net	—			1,148
Net cash (used in) provided by financing activities	(28,955		)	66,599
Net decrease in cash and cash equivalents	(2,479		)	(117,334		)
Cash and cash equivalents - beginning of period	7,512			120,911
Cash and cash equivalents - end of period	$	5,033		$	3,577
Supplemental disclosures:
Cash paid for:
Interest (net of amounts capitalized)	$	27,865		$	17,288
Income taxes (net of refunds received)	$	(32,574	)	$	433

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

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

For the Quarterly Period Ended September 30, 2012

(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 in the exploration, development and production of oil and natural gas in various domestic onshore regions including Texas, the Mid-Continent, Mississippi and Pennsylvania.


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. 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, 2011. Operating results for the nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012. Certain amounts for the 2011 period have been reclassified to conform to the current year presentation.

During the quarter ended September 30, 2012, 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, except for the acquisition of additional acreage in the Eagle Ford Shale (see Note 3) and the offering of common and preferred stock (see Note 11), no subsequent events have occurred that would require recognition in the Condensed Consolidated Financial Statements or disclosure in the Notes to the Condensed Consolidated Financial Statements.


3.	Acquisitions and Divestitures

Property Acquisitions

Eagle Ford Property Acquisitions

In December 2011, we entered into an agreement with an industry partner to jointly explore a 13,500 acre area of mutual interest ("AMI") in Lavaca County, Texas. Under the terms of the agreement, we were required to commence drilling on six wells by September 1, 2012 to earn our entire interest in the acreage as well as carry our partner for its working interest share of the costs of the first three wells. During the quarter ended September 30, 2012 we fulfilled this requirement and through the nine months ended September 30, 2012, we drilled a total of seven (6.2 net) successful wells on the acreage. Depending upon the future participation elections made by our partners, our working interest in wells drilled in the AMI is expected to be at least 57 percent.

In October 2012, we acquired approximately 4,100 net acres in the Eagle Ford Shale in Gonzales and Lavaca Counties for approximately $10 million. Under existing joint venture agreements, other non-operated working interest owners are expected to acquire approximately 17 percent of the net acreage in Gonzales County and approximately 46 percent of the net acreage in Lavaca County, increasing our net Eagle Ford Shale acreage position by approximately 3,000 net acres to a total of approximately 30,000 net acres.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Divestitures

Oil and Gas Properties

On July 31, 2012, we sold substantially all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for approximately $100 million, prior to deducting transaction costs and customary purchase and sale adjustments. Certain leases subject to the sale, representing approximately $4 million of value, are awaiting consent by the underlying property or mineral owners to be transferred. Such consents are expected to be obtained by the end of 2012. Through September 30, 2012, we received proceeds of $92.2 million, net of transaction costs and customary closing adjustments, and recognized a gain of $1.7 million in connection with the transaction. The sold assets included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. The sold assets had net production of approximately 20 million cubic feet of natural gas equivalent per day, almost 100 percent of which was dry natural gas. Estimated proved reserves associated with the assets, as determined by our third party reserve engineer as of December 31, 2011, were approximately 106 billion cubic feet of natural gas equivalent, of which 96 percent were proved developed. An impairment charge of $28.6 million was recognized in the second quarter of 2012 with respect to these assets.

In January 2012, we sold our remaining undeveloped acreage in Butler and Armstrong Counties in Pennsylvania for proceeds of $1.0 million, net of transaction costs. We recognized a gain of $0.6 million in connection with this transaction.


4.	Accounts Receivable and Major Customers

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



	September 30, 2012			December 31, 2011
Customers	$	42,079		$	49,763
Joint interest partners	25,485			22,755
Other	3,738			1,695
	71,302			74,213
Less: Allowance for doubtful accounts	(1,263		)	(1,781		)
	$	70,039		$	72,432

For the nine months ended September 30, 2012 and 2011, five customers accounted for $155.2 million and $43.5 million, or approximately 66% and 20%, of our total consolidated product revenues. As of September 30, 2012 and December 31, 2011, $27.1 million and $29.9 million, or approximately 39% and 41%, 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 oil and gas price volatility as well as the volatility in interest rates attributable to our debt instruments. We are not engaged in the trading of derivative instruments for speculative purposes. The derivative instruments are placed with financial institutions that we believe are acceptable credit risks. Our derivative instruments are not formally designated as hedges.

Commodity Derivatives

We utilize collars, swaps and swaptions to hedge against the variability in cash flows associated with anticipated sales of our future oil and gas production. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues from favorable price movements. As of September 30, 2012, we have hedged our future crude oil production through 2014 to the greatest extent permitted by our revolving credit agreement (“Revolver”) and our internal policies.

We determine the fair values of our commodity derivative instruments based on discounted cash flows derived from third-party quoted forward prices for NYMEX Henry Hub gas and West Texas Intermediate crude oil closing prices as of the

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

end of the reporting period. The discounted cash flows utilize 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, 2012:



		Average Volume Per Day	Weighted Average Price				Fair Value
	Instrument	Average Volume Per Day	Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2012	Swaps	10,000	$	5.10			$	1,636	$	—
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2012	Collars	1,000	$	90.00	$	97.00	52		—
First quarter 2013	Collars	1,000	$	90.00	$	100.00	105		—
Second quarter 2013	Collars	1,000	$	90.00	$	100.00	93		—
Third quarter 2013	Collars	1,000	$	90.00	$	100.00	124		—
Fourth quarter 2013	Collars	1,000	$	90.00	$	100.00	161		—
Fourth quarter 2012	Swaps	3,000	$	104.40			3,211		—
First quarter 2013	Swaps	2,250	$	103.51			1,954		—
Second quarter 2013	Swaps	2,250	$	103.51			1,912		—
Third quarter 2013	Swaps	1,500	$	102.77			1,230		—
Fourth quarter 2013	Swaps	1,500	$	102.77			1,294		—
First quarter 2014	Swaps	2,000	$	100.44			1,406		—
Second quarter 2014	Swaps	2,000	$	100.44			1,540		—
Third quarter 2014	Swaps	1,500	$	100.20			1,218		—
Fourth quarter 2014	Swaps	1,500	$	100.20			1,274		—
First quarter 2013	Swaption	1,100	$	100.00			—		299
Second quarter 2013	Swaption	1,000	$	100.00			—		267
Third quarter 2013	Swaption	900	$	100.00			—		203
Fourth quarter 2013	Swaption	750	$	100.00			—		133
First quarter 2014	Swaption	812	$	100.00			—		386
Second quarter 2014	Swaption	812	$	100.00			—		386
Third quarter 2014	Swaption	812	$	100.00			—		386
Fourth quarter 2014	Swaption	812	$	100.00			—		386
Settlements to be received in subsequent period							886		—

Interest Rate Swaps

In February 2012, we entered into an interest rate swap agreement to establish variable rates on approximately one-third of the outstanding obligation under our 7.25% Senior Notes due 2019 (“2019 Senior Notes”). In May 2012, we terminated this agreement and received $1.2 million in cash proceeds.

During the nine months ended September 30, 2011, we had an interest rate swap agreement in effect that established variable rates on approximately one-third of the face amount of the outstanding obligation under our 10.375% Senior Notes due 2016 (“2016 Senior Notes”). In August 2011, we terminated this agreement and received $2.9 million in cash proceeds.

As of September 30, 2012, we had no interest rate derivative instruments outstanding.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 Operations. The following table summarizes the effects of our derivative activities for the periods presented:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012		2011
Impact by contract type:
Commodity contracts	$	(12,271	)	$	11,293		$	29,844	$	18,598
Interest rate contracts	—			205			1,406		1,229
	$	(12,271	)	$	11,498		$	31,250	$	19,827
Realized and unrealized impact:
Cash received for:
Commodity contract settlements	$	9,238		$	5,607		$	22,783	$	16,484
Interest rate contract settlements	—			2,920			1,406		3,818
	9,238			8,527			24,189		20,302
Unrealized gains (losses) attributable to:
Commodity contracts	(21,509		)	5,686			7,061		2,114
Interest rate contracts	—			(2,715		)	—		(2,589		)
	(21,509		)	2,971			7,061		(475		)
	$	(12,271	)	$	11,498		$	31,250	$	19,827

The effects of derivative gains (losses) and cash settlements of our commodity and interest rate derivatives are reported as adjustments to reconcile net income (loss) to net cash provided by operating activities. 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 dates presented:



		Fair Values as of
		September 30, 2012				December 31, 2011
Type	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Commodity contracts	Derivative assets/liabilities - current	$	11,252	$	817	$	18,987	$	3,549
Interest rate contracts	Derivative assets/liabilities - current	—		—		—		—
		11,252		817		18,987		3,549
Commodity contracts	Derivative assets/liabilities - noncurrent	6,892		1,677		—		6,850
Interest rate contracts	Derivative assets/liabilities - noncurrent	—		—		—		—
		6,892		1,677		—		6,850
		$	18,144	$	2,494	$	18,987	$	10,399

As of September 30, 2012, we reported a commodity derivative asset of $18.1 million. The contracts associated with this position are with six 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 have not received any cash collateral from our counterparties with respect to our derivative asset positions. No significant uncertainties exist related to the collectability of amounts that may be owed to us by these counterparties.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


6.	Property and Equipment

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



	September 30, 2012			December 31, 2011
Oil and gas properties:
Proved	$	2,204,593		$	2,239,186
Unproved	99,384			120,288
Total oil and gas properties	2,303,977			2,359,474
Other property and equipment	95,591			143,285
Total property and equipment	2,399,568			2,502,759
Accumulated depreciation, depletion and amortization	(654,477		)	(725,184		)
	$	1,745,091		$	1,777,575


7.	Long-Term Debt

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



	September 30, 2012			December 31, 2011
Revolving credit facility	$	77,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)	294,447			293,561
Senior notes due 2019	300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)	4,884			4,746
	676,331			697,307
Less: Current portion of long-term debt	(4,884		)	(4,746		)
	$	671,447		$	692,561

Revolving Credit Facility

In September 2012, we entered into the Revolver which replaced our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving commitment and an accordion feature that allows us to increase the commitment by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver is governed by a borrowing base calculation and the availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver is $300 million. The borrowing base will be re-determined based on a semi-annual review of our total proved oil, NGL and natural gas reserves starting in the spring of 2013. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. We had letters of credit of $1.6 million outstanding as of September 30, 2012. As of September 30, 2012, our available borrowing capacity under the Revolver, as reduced by outstanding borrowings and letters of credit, was $221.4 million.

In September 2012, we capitalized $1.9 million of debt issuance costs in connection with the Revolver which will be amortized as a component of interest expense over the five year term. Capitalized debt issuance costs attributable to our previous revolving credit facility of $3.2 million were expensed as a loss on the extinguishment of debt during the quarter ended September 30, 2012.

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 (“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% and (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.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Commitment fees are charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2012, the actual interest rate on the borrowings under the Revolver was 4.0%. This rate represents the prime rate option which applied to the initial borrowings through October 3, 2012 at which time the Adjusted LIBOR interest rate went into effect. The Adjusted LIBOR margin applicable to the initial borrowings subsequent to the conversion from the prime rate option was 1.75%.

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 parent company and 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.

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 through December 31, 2013, 4.25 to 1.0 through June 30, 2014 and then 4.0 to 1.0 through maturity.

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 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 starting 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 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. Beginning in April 2015, we may redeem all or part of the 2019 Senior Notes at a redemption price starting 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 classified as current maturities of 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

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

was 8.5%. The $4.9 million of outstanding principal amount due on the Convertible Notes will be paid on November 15, 2012 and will be funded by cash on hand or by borrowings under the Revolver.

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, including 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.

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



	September 30, 2012			December 31, 2011
Principal	$	4,915		$	4,915
Unamortized discount	(31		)	(169		)
Net carrying amount of liability component	$	4,884		$	4,746
Carrying amount of equity component	$	35,201		$	35,201

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Contractual interest expense	$	55	$	55	$	166	$	3,064
Accretion on original issue discount	47		43		138		2,308
Amortization of debt issuance costs	8		7		22		396
	$	110	$	105	$	326	$	5,768

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


8.	Additional Balance Sheet Detail

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



	September 30, 2012		December 31, 2011
Other current assets:
Tubular inventory and well materials	$	4,973	$	14,251
Prepaid expenses	610		699
	$	5,583	$	14,950
Other assets:
Debt issuance costs	$	13,759	$	16,993
Assets of supplemental employee retirement plan ("SERP")	3,200		3,088
Other	1,888		51
	$	18,847	$	20,132
Accounts payable and accrued liabilities:
Trade accounts payable	$	30,081	$	30,186
Drilling costs	31,826		30,948
Royalties	13,244		15,235
Production and franchise taxes	6,858		3,495
Compensation - related	5,531		5,186
Interest	19,155		5,964
Other	5,326		3,490
	$	112,021	$	94,504
Other liabilities:
Firm transportation obligation	$	14,443	$	—
Asset retirement obligations	4,543		6,283
Defined benefit pension obligations	1,660		1,763
Postretirement health care benefit obligations	3,035		3,022
Deferred compensation - SERP obligation and other	3,300		3,172
Other	2,277		1,647
	$	29,258	$	15,887


9.	Fair Value Measurements

We apply the authoritative accounting provisions for measuring the fair values of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive upon the sale of an asset or that we would expect to 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, 2011.

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, 2012, the carrying values of all of these financial instruments, except the portion of long-term debt with fixed interest rates, approximated fair value.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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 these debt obligations as of the dates presented:



	September 30, 2012				December 31, 2011
	Fair Value		Carrying Value		Fair Value		Carrying Value
Senior Notes due 2016	$	311,250	$	294,447	$	319,500	$	293,561
Senior Notes due 2019	279,000		300,000		280,500		300,000
Convertible Notes	4,915		4,884		4,925		4,746
	$	595,165	$	599,331	$	604,925	$	598,307

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 fair values of those assets and liabilities as of the dates presented:



	As of September 30, 2012
	Fair Value Measurement			Fair Value Measurement Classification
Description	Fair Value Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets - current	$	11,252		$	—		$	11,252		$	—
Commodity derivative assets - noncurrent	6,892			—			6,892			—
Assets of SERP	3,200			3,200			—			—
Liabilities:
Commodity derivative liabilities - current	(817		)	—			(817		)	—
Commodity derivative liabilities - noncurrent	(1,677		)	—			(1,677		)	—
Deferred compensation - SERP obligation and other	(3,296		)	(3,296		)	—			—
	$	15,554		$	(96	)	$	15,650		$	—



	As of December 31, 2011
	Fair Value Measurement			Fair Value Measurement Classification
Description	Fair Value Measurement			Level 1			Level 2			Level 3
Assets:
Commodity derivative assets – current	$	18,987		$	—		$	18,987		$	—
Assets of SERP	3,088			3,088			—			—
Liabilities:
Commodity derivative liabilities - current	(3,549		)	—			(3,549		)	—
Commodity derivative liabilities - noncurrent	(6,850		)	—			(6,850		)	—
Deferred compensation - SERP obligation and other	(3,168		)	(3,168		)	—			—
	$	8,508		$	(80	)	$	8,588		$	—

Changes in economic conditions or model-based valuation techniques may require the transfer of financial instruments from one level of the fair value hierarchy to another level. In such instances, the transfer is deemed to have occurred at the beginning of the quarterly period in which the event or change in circumstances that caused the transfer occurred. There were no transfers during the three or nine months ended September 30, 2012 and 2011.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

We used the following methods and assumptions to estimate fair values for the financial assets and liabilities described below:

•

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


•	Assets of SERP: We hold various publicly traded equity securities in a Rabbi Trust as assets for funding certain deferred compensation obligations. The fair values are based on quoted market prices, which are level 1 inputs.


•	Deferred compensation – SERP obligation and other: Certain of our deferred compensation obligations are ultimately to be settled in cash based on the underlying fair value of certain assets, including those held in the Rabbi Trust. 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, indicative sales prices for properties, 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.


10.	Commitments and Contingencies

Commitments

Our most significant commitments consist of the purchase of oil and gas well drilling services, capacity utilization under firm transportation service agreements and operating leases for field and office equipment and office space, as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2011.

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, results of operations or cash flows. During 2010, we established a $0.9 million reserve for a litigation matter pertaining to certain properties that remains outstanding as of September 30, 2012. In addition, as of September 30, 2012, we have an ARO liability of approximately $4.5 million attributable to the plugging of abandoned wells.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)


11.	Shareholders’ Equity

The following table summarizes the components of our shareholders’ equity and the changes therein as of and for the nine months ended September 30, 2012 and 2011:



	As of December 31, 2011			Net Loss			Dividends Paid ($0.1125 per share)			All Other Changes			As of September 30, 2012
Common stock	$	270		$	—		$	—		$	1		$	271
Paid-in capital	690,131			—			—			4,228			694,359
Retained earnings	157,242			(50,148		)	(5,176		)	—			101,918
Deferred compensation obligation	3,620			—			—			(548		)	3,072
Accumulated other comprehensive loss	(1,084		)	—			—			69			(1,015		)
Treasury stock	(3,870		)	—			—			547			(3,323		)
Total shareholders' equity	$	846,309		$	(50,148	)	$	(5,176	)	$	4,297		$	795,282



	As of December 31, 2010			Net Loss			Dividends Paid ($0.16875 per share)			All Other Changes			As of September 30, 2011
Common stock	$	267		$	—		$	—		$	2		$	269
Paid-in capital	680,981			—			—			6,571			687,552
Retained earnings	300,473			(104,976		)	(7,736		)	—			187,761
Deferred compensation obligation	2,743			—			—			685			3,428
Accumulated other comprehensive loss	(938		)	—			—			102			(836		)
Treasury stock	(3,250		)	—			—			(561		)	(3,811		)
Total shareholders' equity	$	980,276		$	(104,976	)	$	(7,736	)	$	6,799		$	874,363

In October 2012, we completed a registered offering of 9.2 million shares of our common stock that provided approximately $44 million of net proceeds before issuance costs. Concurrently, we completed a registered offering of 1,150,000 depositary shares each representing 1/100th interest in a share of our 6% Series A Convertible Perpetual Preferred Stock (“6% Preferred Stock”), that provided approximately $111 million of net proceeds before issuance costs. The proceeds from the combined offerings were used to repay outstanding borrowings under our Revolver and for general corporate purposes.

Each depositary share of the 6% Preferred Stock has a liquidation preference of $100.00 per share and is entitled to an annual dividend of $6.00 payable quarterly in cash, common stock or a combination thereof. Each depositary share of the 6% Preferred Stock is convertible at the option of the holder at an initial conversion rate of 16.6667 shares of our common stock per depositary share, or $6.00 per share of common stock. The conversion price represents a premium of 20 percent relative to the common stock offering price of $5.00 per share. The 6% Preferred Stock is not redeemable by us at any time. On or after October 15, 2017, we may cause all or a portion of the depositary shares of the 6% Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion rate if certain conditions are met.


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 vest 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, either at the end of the three years or 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 Operations.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

Equity-Classified Awards

Most of the awards issued under our stock compensation plans are classified as equity instruments because they result in the issuance of common stock on the date of grant, upon exercise or are otherwise payable in common stock upon vesting, as applicable. The recognition of compensation cost attributable to these awards is a non-cash item of expense.

Liability-Classified Awards

In February 2012, we granted performance-based restricted stock units (“PBRSUs”) to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.

The following table summarizes share-based compensation expense recognized for the periods presented:



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Equity-classified awards:
Stock option plans	$	950	$	1,354	$	3,108	$	4,141
Common, deferred, restricted and time-based restricted unit plans	332		466		1,125		1,488
	1,282		1,820		4,233		5,629
Liability-classified awards	165		—		790		—
	$	1,447	$	1,820	$	5,023	$	5,629


13.	Restructuring and Exit Activities

During the quarter ended September 30, 2012, we completed an organizational restructuring in conjunction with the sale of our Appalachian assets. We terminated approximately 30 employees and closed our regional office in Canonsburg, Pennsylvania. We recorded a charge and recognized an obligation in connection with the long-term lease of that office. In addition, we have contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

During 2011, we completed an organizational restructuring due primarily to our decision to exit the Arkoma Basin and to consolidate certain operations functions to our Houston, Texas location. We terminated approximately 40 employees and closed our regional office in Tulsa, Oklahoma. Accordingly, we recorded a charge and recognized an obligation in connection with the long-term lease of that office.

In addition to the accrual of these costs, we adjusted the lease obligation associated with the Tulsa office as a result of a change in estimated sub-lease rental income. Restructuring charges, including the accretion of the lease obligations, are included in the General and administrative expenses caption on our Condensed Consolidated Statements of Operations. The initial charge for the firm transportation commitment is presented as a separate caption on our Condensed Consolidated Statement of Operations.

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

The following table summarizes our restructuring-related obligations as of and for the periods presented:



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Balance at beginning of period	$	251		$	—		$	576		$	64
Employee, office and other costs accrued, net	1,431			1,553			1,283			1,623
Firm transportation charge	17,332			—			17,332			—
Cash payments, net	(1,359		)	(286		)	(1,536		)	(420		)
Balance at end of period	$	17,655		$	1,267		$	17,655		$	1,267

The current portion of these restructuring and exit cost obligations is included in the Accounts payable and accrued expenses caption and the noncurrent portion is included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. As of September 30, 2012, $3.2 million of the total obligations are classified as current while the remaining $14.4 million are classified as noncurrent.


14.	Impairments

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



	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Oil and gas properties	$	—	$	—	$	28,481	$	71,071
Other	700		—		835		—
	$	700	$	—	$	29,316	$	71,071

In September 2012, we recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality. In June 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. In 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these high-cost gas properties in the third quarter of 2011.


15.	Interest Expense

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Interest on borrowings and related fees	$	14,156		$	13,581		$	42,462		$	37,448
Accretion of original issue discount	351			315			1,025			3,103
Amortization of debt issuance costs	706			747			2,082			2,709
Capitalized interest	(234		)	(437		)	(732		)	(1,427		)
	$	14,979		$	14,206		$	44,837		$	41,833

Table of Contents

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (continued)

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						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Net loss¹	$	(32,611	)	$	(6,718	)	$	(50,148	)	$	(104,976	)
Weighted-average shares, basic	46,050			45,817			46,009			45,758
Effect of dilutive securities²	—			—			—			—
Weighted-average shares, diluted	46,050			45,817			46,009			45,758

____________________________________________________________________________

¹Includes a $2.2 million benefit for the three and nine month periods ended September 30, 2012 attributable to a change in the estimated effective state tax rate due primarily to changes in the number of states in which we will have taxable operations subsequent to the sale of our Appalachian assets.

²For each of the three and nine month periods ended September 30, 2012 and 2011, an amount less than 0.1 million of 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.

Table of Contents

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 oil, natural gas liquids and natural gas;


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


•	our ability to generate profits or achieve targeted reserves in our development and exploratory drilling and well operations;


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


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


•	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 cost 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;


•	our ability to successfully monetize select assets and repay our debt;


•	leasehold terms expiring before production can be established;


•	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, 2011.

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.

Table of Contents


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 in the exploration, development and production of oil and natural gas in various domestic onshore regions. We have a geographically diverse asset base with areas of operations in Texas, the Mid-Continent, Mississippi and Pennsylvania regions of the United States. As of December 31, 2011, we had proved oil and gas reserves of approximately 883 billion cubic feet equivalent, or Bcfe. As discussed in the Key Developments that follow, our total reserves were reduced by approximately106 Bcfe as a result of the sale of our Appalachian properties in July 2012. Our current operations include primarily the drilling of horizontal unconventional development wells and exploring for primarily unconventional reserves.

We are currently focused on development and expansion in the Eagle Ford Shale in South Texas. We also pursue select drilling opportunities in the horizontal Granite Wash play in our Mid-Continent region through participation in wells drilled by our joint venture partner.

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



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Total production (MMcfe)	9,024			11,947			30,551			35,817
Daily production (MMcfe per day)	98.0			129.8			111.5			131.1
Daily gas production (MMcf per day)	47.5			87.5			60.3			97.5
Daily oil and NGL production (Bbl per day)	8,430			7,060			8,530			5,580
Product revenues, as reported	$	75,575		$	81,994		$	234,496		$	222,696
Product revenues, as adjusted for derivatives	$	84,812		$	87,601		$	257,279		$	239,180
Operating loss	$	(24,485	)	$	(9,031	)	$	(65,950	)	$	(118,273	)
Interest expense	$	14,979		$	14,206		$	44,837		$	41,833
Cash provided by operating activities	$	74,489		$	39,405		$	190,214		$	103,164
Cash paid for capital expenditures	$	68,958		$	107,193		$	257,194		$	318,274
Cash and cash equivalents at end of period							$	5,033		$	3,577
Debt outstanding, net of discounts, at end of period							$	676,331		$	612,983
Credit available under revolving credit facility at end of period¹							$	221,372		$	283,600
Net development wells drilled	6.0			9.4			18.2			23.8
Net exploratory wells drilled	—			0.1			4.8			6.5

¹As reduced by outstanding borrowings and letters of credit and limited by financial covenants, if applicable.

Table of Contents

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, financial position and cash flows: (i) drilling results in the Eagle Ford Shale and other plays, (ii) continuing to shift the focus of our production from natural gas to oil and natural gas liquids, or NGLs, (iii) entering into a new five-year revolving credit facility, or the Revolver, (iv) completing an offering of common and preferred stock, (v) selling our Appalachian assets and related restructuring and exit activities and (iv) hedging a portion of our oil and natural gas production for the calendar years 2012 through 2014 to the levels permitted by the Revolver and our internal policies. We believe these actions will provide sufficient liquidity in 2013 so that we will be able to fund our capital programs.

Drilling Results and Future Development

During the nine months ended September 30, 2012, we drilled a total of 30 gross (23.0 net) wells, including 20 gross (16.7 net) development wells and five gross (4.7 net) exploratory wells in the Eagle Ford Shale and five gross (1.6 net) development wells in the Granite Wash.

During the third quarter of 2012, we drilled six (5.0 net) operated wells in the Eagle Ford Shale, all of which were successful. Since early August, we have completed eight (6.7 net) and acquired one (1.0 net) Eagle Ford Shale wells, bringing the total to 59 (49.1 net) producing wells, with one (0.9 net) well being completed and the 61st through 63rd wells being drilled. The average peak gross production rate per well for the 49 wells we completed with full-length laterals was 986 barrels of oil equivalent per day, or BOEPD. The initial 30-day average gross production rate for 45 of these 49 wells with a 30-day production history was 656 BOEPD. Our Eagle Ford Shale production was approximately 6,300 net BOEPD during the third quarter of 2012, with oil comprising approximately 84 percent, NGLs approximately nine percent and natural gas approximately seven percent. We have allocated approximately 90 percent of our capital expenditures during 2012 to activities in the Eagle Ford Shale.

Included in the totals presented above for the Eagle Ford Shale are four (3.8 net) exploratory wells and three (2.5 net) development wells in Lavaca County, Texas drilled under a joint exploration agreement with an industry partner that we entered into in December 2011. Under the terms of the agreement, we were required to commence drilling on six wells by September 1, 2012 to earn our entire interest in the acreage as well as carry our partner for its working interest share of the costs of the first three wells. We fulfilled this requirement during the third quarter. Depending upon the future participation elections made by our partners, our working interest in wells drilled in the AMI is expected to be at least 57 percent.

During the third quarter of 2012, we drilled four (1.1 net) non-operated wells in the Granite Wash; one (0.5 net) well was successful with final results not yet established on three (0.6 net) wells. We experienced operational problems while drilling our first horizontal Viola Lime well in Jefferson County, Oklahoma and, as a result, shortened the well's planned lateral length by approximately 3,000 feet. We concluded that the drilled lateral length of approximately 1,100 feet was sufficient to test the concept of the prospect and we stimulated the shortened lateral with a seven-stage acid frac. The production rate is less than 10 barrels of oil per day, on pump, which is much less than anticipated. The prospect is being re-evaluated with the possibility of drilling an additional well in 2013 or attempting a recompletion in an up-hole interval in the existing well. We have an acreage position of approximately 9,600 acres in this play.

Production Focus

Since 2011, we have allocated approximately 90 percent of our capital expenditures to explore and develop primarily oil and NGL-rich areas, primarily in the Eagle Ford Shale. Accordingly, we are continuing to transform our production profile away from natural gas to oil and NGLs. Approximately 52 percent of our total production on an equivalent basis during the quarter ended September 30, 2012 was attributable to oil and NGLs, an increase of approximately 19 percent over the prior year period. For the quarter ended September 30, 2012, approximately 84 percent of our product revenues were attributable to oil and NGLs, an increase of approximately 33 percent over the corresponding prior year period.

Table of Contents

Completion of a New Credit Facility

In September 2012, we entered into the Revolver which replaced our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving commitment and an accordion feature to expand commitment amounts by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver also includes a $20 million sublimit for the issuance of letters of credit. The Revolver has an initial borrowing base of $300 million, which is $70 million higher than the borrowing base under our previous revolving credit facility. The applicable interest rate margin under the Revolver ranges from the London Interbank Offered Rate, or LIBOR, plus 1.50 percent to LIBOR plus 2.50 percent, depending upon the amount drawn at any given time. This rate is unchanged from our previous credit facility. The maximum leverage ratio (net debt divided by Adjusted EBITDAX, as defined in the Revolver) is 4.50 through December 31, 2013, 4.25 through June 30, 2014 and 4.00 through maturity in 2017. The borrowing base under the Revolver will be re-determined based on a semi-annual review of our total proved crude oil, NGL and natural gas reserves starting in the spring of 2013.

Common and Preferred Stock Offering

In October 2012, we completed a registered offering of 9.2 million shares of our common stock that provided approximately $44 million of net proceeds before issuance costs. Concurrently, we completed a registered offering of 1,150,000 depositary shares each representing 1/100th interest in a share of our 6% Series A Convertible Perpetual Preferred Stock, or 6% Preferred Stock, that provided approximately $111 million of net proceeds before issuance costs. The proceeds from the combined offerings were used to fully repay outstanding borrowings under our Revolver and for general corporate purposes.

Disposition of Appalachian Assets

On July 31, 2012, we sold all of our assets in the Appalachian region, with the exception of the Marcellus Shale, for $100 million, prior to deducting transaction costs and purchase and sale adjustments. Certain leases subject to the sale, representing approximately $4 million of value, are awaiting consent by the underlying property or mineral owners to be transferred. Such consents are expected to be obtained by the end of 2012. Through September 30, 2012, we received proceeds of $92.2 million, net of transaction costs and customary closing adjustments, and recognized a gain of $1.7 million in connection with the transaction. The sold assets included vertical and horizontal coalbed methane and vertical conventional properties, a gathering system and royalty interests. The sold assets had net production of approximately 20 million cubic feet of dry natural gas equivalent per day during June 2012, almost 100 percent of which was natural gas. As a result of the divestiture, our 2012 production will decrease by an estimated 2.9 Bcfe. Estimated proved reserves associated with the sold assets, as determined by our third party reserve engineer as of December 31, 2011, were approximately 106 Bcfe, of which 96 percent were proved developed. An impairment charge of $28.6 million was recognized in the second quarter of 2012 with respect to these assets.

During the quarter ended September 30, 2012, we recorded certain restructuring and exit costs in connection with the sale, including those attributable to the closing of our office in Canonsburg, Pennsylvania. Furthermore, we have contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale, we no longer have production to satisfy these commitments. While we intend to sell our unused firm transportation in the future to the extent possible, we recorded a charge of $17.3 million representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

Commodity Hedging Activities

As of October 26, 2012, we have hedged the maximum volume of oil production as permitted under the terms of the Revolver for calendar years 2013 and 2014. For the remainder of 2012, we have hedged approximately 68 percent of our estimated oil production at weighted-average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel. For 2013, we have approximately 31 to 48 percent of our estimated oil production hedged at weighted-average floor/swap and ceiling prices of between $97.66 and $102.43 per barrel. For 2014, we have approximately 15 to 24 percent of our estimated oil production hedged at a weighted-average floor/swap and ceiling prices of $100.20 and $100.44 per barrel. Our natural gas hedges represent approximately 24 percent of our estimated production for the balance of the year at a weighted-average swap price of $5.10 per MMBtu. For 2013, we have approximately 36 to 40 percent of our estimated natural gas production hedged at weighted-average floor/swap and ceiling prices of $3.68 and $4.21 per MMBtu.

Table of Contents

Results of Operations

Three Months Ended September 30, 2012 Compared to the Three Months Ended September 30, 2011

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



	Three Months Ended
	September 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Total production:
Natural gas (MMcf)	4,371			8,051			(3,680		)	(46	)%
Crude oil (MBbl)	573			427			146			34	%
NGLs (MBbl)	202			222			(20		)	(9	)%
Total production (MMcfe)	9,024			11,947			(2,923		)	(24	)%
Realized prices, before derivatives:
Natural gas ($/Mcf)	$	2.72		$	4.24		$	(1.52	)	(36	)%
Crude oil ($/Bbl)	99.45			87.04			12.41			14	%
NGLs ($/Bbl)	32.96			48.00			(15.04		)	(31	)%
Total ($/Mcfe)	$	8.37		$	6.86		$	1.51		22	%
Revenues
Natural gas	$	11,909		$	34,171		$	(22,262	)	(65	)%
Crude oil	56,995			37,147			19,848			53	%
Natural gas liquids (NGLs)	6,671			10,676			(4,005		)	(38	)%
Total product revenues	75,575			81,994			(6,419		)	(8	)%
Gain on sales of property and equipment, net	1,573			71			1,502			NM
Other	551			1,288			(737		)	(57	)%
Total revenues	77,699			83,353			(5,654		)	(7	)%
Operating expenses
Lease operating	6,206			8,458			2,252			27	%
Gathering, processing and transportation	3,127			2,952			(175		)	(6	)%
Production and ad valorem taxes	4,589			3,391			(1,198		)	(35	)%
General and administrative	11,634			12,635			1,001			8	%
Exploration	9,265			19,303			10,038			52	%
Depreciation, depletion and amortization	49,331			45,345			(3,986		)	(9	)%
Impairments	700			—			(700		)	NM
Loss on firm transportation commitment	17,332			—			(17,332		)	NM
Other	—			300			300			NM
Total operating expenses	102,184			92,384			(9,800		)	(11	)%
Operating loss	(24,485		)	(9,031		)	(15,454		)	(171	)%
Other income (expense)
Interest expense	(14,979		)	(14,206		)	(773		)	(5	)%
Loss on extinguishment of debt	(3,144		)	(1,165		)	(1,979		)	NM
Derivatives	(12,271		)	11,498			(23,769		)	NM
Other	60			61			(1		)	(2	)%
Loss before income taxes	(54,819		)	(12,843		)	(41,976		)	(327	)%
Income tax benefit	22,208			6,125			16,083			263	%
Net loss	$	(32,611	)	$	(6,718	)	$	(25,893	)	(385	)%
NM - Not meaningful

Table of Contents

Production

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



Natural gas	Three Months Ended September 30,		Favorable		Three Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas	1,674	2,154	(479	)	18.2	23.4	(5.2	)	(22	)%
Appalachia	639	2,273	(1,633	)	6.9	24.7	(17.8	)	(72	)%
Mid-Continent	833	2,090	(1,257	)	9.1	22.7	(13.6	)	(60	)%
Mississippi	1,224	1,535	(311	)	13.3	16.7	(3.4	)	(20	)%
	4,371	8,051	(3,681	)	47.5	87.5	(40	)	(46	)%



Crude oil	Three Months Ended September 30,		Favorable		Three Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)				(MBbl per day)
Texas	502.9	323.7	179.2		5.47	3.52	1.95		55	%
Appalachia	0.4	0.5	(0.1	)	—	0.01	(0.01	)	100	%
Mid-Continent	66.3	98.4	(32.1	)	0.72	1.07	(0.35	)	(33	)%
Mississippi	3.5	4.2	(0.7	)	0.04	0.05	(0.01	)	(20	)%
	573.1	426.8	146.3		6.23	4.65	1.58		34	%



NGLs	Three Months Ended June 30,		Favorable		Three Months Ended June 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)				(MBbl per day)
Texas	118.8	135.3	(16.5	)	1.29	1.47	(0.18	)	(12	)%
Appalachia	0.2	0.2	—		—	—	—		NM
Mid-Continent	83.4	86.9	(3.5	)	0.91	0.94	(0.03	)	(3	)%
	202.4	222.4	(20.0	)	2.20	2.41	(0.21	)	(9	)%



Combined	Three Months Ended September 30,		Favorable		Three Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcfe)				(MMcfe per day)
Texas	5,405	4,908	497		58.7	53.3	5.4		10	%
Appalachia	643	2,277	(1,634	)	7.0	24.7	(17.7	)	(72	)%
Mid-Continent	1,731	3,201	(1,470	)	18.8	34.8	(16	)	(46	)%
Mississippi	1,245	1,560	(315	)	13.5	17.0	(3.5	)	(21	)%
	9,024	11,947	(2,922	)	98.0	129.8	(31.8	)	(24	)%
Certain results in the tables above may not calculate due to rounding.

The decline in total production during the quarter ended September 30, 2012 compared to the corresponding quarter of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Appalachian properties in July 2012 and Arkoma Basin properties in August 2011. The effect of the sale of the Appalachian properties was approximately 1.5 Bcfe while the effect of the Arkoma Basin properties was 0.4 Bcfe during the quarter. The natural declines in production were partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 52% of total production on an equivalent basis in the quarter ended September 30, 2012 was attributable to oil and NGLs, a 19% increase over the prior year quarter. The shift in production mix reflects our focus on oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the quarter ended September 30, 2012, our Eagle Ford Shale production of 3.5 Bcfe represented 39% of our total production. We had approximately 2.1 Bcfe of production from this play during the corresponding 2011 quarter.

Table of Contents

Product Revenues and Prices

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



Natural gas	Three Months Ended September 30,				Favorable			Three Months Ended September 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcf)
Texas	$	3,386	$	8,284	$	(4,898	)	$	2.02	$	3.85	$	(1.83	)
Appalachia	1,831		9,478		(7,647		)	2.86		4.17		(1.31		)
Mid-Continent	3,109		9,726		(6,617		)	3.73		4.65		(0.92		)
Mississippi	3,583		6,683		(3,100		)	2.93		4.35		(1.42		)
	$	11,909	$	34,171	$	(22,262	)	$	2.72	$	4.24	$	(1.52	)



Crude oil	Three Months Ended September 30,				Favorable			Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Bbl)
Texas	$	50,498	$	28,215	$	22,283		$	100.41	$	87.16	$	13.25
Appalachia	34		29		5			85.00		58.00		27.00
Mid-Continent	6,104		8,481		(2,377		)	92.07		86.19		5.88
Mississippi	359		422		(63		)	102.57		100.48		2.09
	$	56,995	$	37,147	$	19,848		$	99.45	$	87.04	$	12.41



NGLs	Three Months Ended September 30,				Favorable			Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Bbl)
Texas	$	3,838	$	6,881	$	(3,043	)	$	32.31	$	50.86	$	(18.55	)
Appalachia	10		10		—			50.00		50.00		—
Mid-Continent	2,823		3,785		(962		)	33.85		43.56		(9.71		)
	$	6,671	$	10,676	$	(4,005	)	$	32.96	$	48.00	$	(15.04	)



Combined	Three Months Ended September 30,				Favorable			Three Months Ended June 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcfe)
Texas	$	57,722	$	43,380	$	14,342		$	10.68	$	8.84	$	1.84
Appalachia	1,875		9,517		(7,642		)	2.92		4.18		(1.26		)
Mid-Continent	12,036		21,992		(9,956		)	6.95		6.87		0.08
Mississippi	3,942		7,105		(3,163		)	3.17		4.55		(1.38		)
	$	75,575	$	81,994	$	(6,419	)	$	8.37	$	6.86	$	1.51

As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $0.7 million of favorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in our Mid-Continent region. In addition, the sale of our Appalachian assets resulted in a reduction to total revenues of $5.8 million during the three month period. The following table provides an analysis of the change in our revenues for the three months ended September 30, 2012 as compared to the three months ended September 30, 2011:



	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(15,621	)	$	(6,641	)	$	(22,262	)
Crude oil	12,732			7,116			19,848
NGLs	(956		)	(3,049		)	(4,005		)
	$	(3,845	)	$	(2,574	)	$	(6,419	)

Table of Contents

Effects of Derivatives

Our oil and gas revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. During the three months ended September 30, 2012 and 2011, we received $9.2 million and $5.6 million in net cash settlements from oil and gas derivatives.

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
	2012		2011		(Unfavorable)			% Change
Natural gas revenues as reported	$	11,909	$	34,171	$	(22,262	)	(65	)%
Cash settlements on natural gas derivatives, net	4,604		5,075		(471		)	(9	)%
Natural gas revenues adjusted for derivatives	$	16,513	$	39,246	$	(22,733	)	(58	)%
Natural gas prices per Mcf, as reported	$	2.72	$	4.24	$	(1.52	)	(36	)%
Cash settlements on natural gas derivatives per Mcf	1.05		0.63		0.42			67	%
Natural gas prices per Mcf adjusted for derivatives	$	3.77	$	4.87	$	(1.10	)	(23	)%
Crude oil revenues as reported	$	56,995	$	37,147	$	19,848		53	%
Cash settlements on crude oil derivatives, net	4,633		532		4,101			(771	)%
Crude oil revenues adjusted for derivatives	$	61,628	$	37,679	$	23,949		64	%
Crude oil prices per Bbl, as reported	$	99.45	$	87.04	$	12.41		14	%
Cash settlements on crude oil derivatives per Bbl	8.08		1.25		6.83			(546	)%
Crude oil prices per Bbl adjusted for derivatives	$	107.53	$	88.29	$	19.24		22	%

Gain on Sales of Property and Equipment

We recognized a gain of $1.7 million on the sale of our Appalachian assets during the quarter ended September 30, 2012. In addition, we recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.

Other Income

Other income decreased during the quarter ended September 30, 2012 due primarily to a $1.3 million settlement received in the prior year period from a partner attributable to oil and gas properties that we previously held in the Appalachian region.

Operating Expenses

As discussed below, we experienced an absolute decrease in several operating expenses. Certain expenses increased on a unit of production basis, however, as a result of the sale of our Appalachian properties as well as declining natural gas production.

Table of Contents

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



	Three Months Ended
	September 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Lease operating	$	0.69	$	0.71	$	0.02		3	%
Gathering, processing and transportation	0.35		0.25		(0.10		)	(40	)%
Production and ad valorem taxes	0.51		0.28		(0.23		)	(82	)%
General and administrative excluding share-based compensation and restructuring charges	0.97		0.78		(0.19		)	(24	)%
General and administrative	1.29		1.06		(0.23		)	(22	)%
Depreciation, depletion and amortization	5.47		3.80		(1.67		)	(44	)%

Lease Operating

Lease operating expense decreased on an absolute basis and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression and water disposal costs. Certain expense decreases were also attributable to the sale of our Appalachian properties in July 2012 and our Arkoma Basin properties in August 2011. Cost decreases were partially offset by higher chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased during the 2012 period, despite lower overall production volumes, due primarily to higher processing costs associated with NGLs in the 2012 period.

Production and Ad Valorem Taxes

Production and ad valorem taxes were higher during the 2012 period, due primarily to a property tax recovery of $1.2 million attributable to wells in West Virginia during the 2011 period. The effect of this increase was partially offset by lower natural gas volumes and prices in the 2012 period as compared to the 2011 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
	2012		2011		(Unfavorable)			% Change
Recurring general and administrative expenses	$	8,756	$	9,262	$	506		5	%
Share-based compensation (liability-classified)	165		—		(165		)	NM
Share-based compensation (equity-classified)	1,282		1,820		538			30	%
Restructuring expenses	1,431		1,553		122			8	%
	$	11,634	$	12,635	$	1,001		8	%

Recurring general and administrative expenses decreased due to reduced headcount and lower support costs primarily attributable to restructuring actions taken during 2012 in connection with the sale of our Appalachian properties as well restructuring actions taken during 2011 related to the sale of our Arkoma Basin properties. Liability-classified share-based compensation is attributable to our performance-based restricted stock units, or PBRSUs, issued in 2012, which are payable in cash upon achievement of certain market-based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the 2012 period due primarily to a lower number of awards granted. Restructuring expenses for both the 2012 and 2011 periods include termination benefits and office relocation costs. The 2012 charge also includes a provision for lease costs associated with our Canonsburg, Pennsylvania office.

Table of Contents

Exploration

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



	Three Months Ended
	September 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Unproved leasehold amortization	$	8,310	$	11,036	$	2,726		25	%
Dry hole costs	—		340		340			100	%
Geological and geophysical costs	83		2,899		2,816			97	%
Drilling rig charges	—		4,778		4,778			100	%
Other, primarily delay rentals	872		250		(622		)	(249	)%
	$	9,265	$	19,303	$	10,038		52	%

Unproved leasehold amortization declined during the 2012 period as certain properties, primarily in the Eagle Ford Shale, were transferred to proved in the second half of 2011 and the first nine months of 2012. In addition, geological and geophysical costs decreased during the 2012 period because our efforts in that period were concentrated in the Eagle Ford Shale whereas in the prior year period we conducted exploratory prospect activities in multiple areas. The 2011 period also includes rig-related charges we incurred in connection with the 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
	2012		2011		(Unfavorable)			% Change
Depletion	$	48,612	$	44,146	$	(4,466	)	(10	)%
Depreciation	642		1,094		452			41	%
Amortization	77		105		28			27	%
	$	49,331	$	45,345	$	(3,986	)	(9	)%



	DD&A Variance Due to
	Production		Rates			Total
Three months ended September 30, 2012 compared to 2011	$	11,092	$	(15,078	)	$	(3,986	)

The effect of lower overall production volume on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $5.39 per Mcfe for the 2012 period from $3.70 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Table of Contents

Impairments

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



	Three Months Ended
	September 30,				Favorable
	2,012		2,011		(Unfavorable)			% Change
Oil and gas properties	$	—	$	—	$	—		NM
Other	700		—		(700		)	NM
	$	700	$	—	$	(700	)	NM

In September 2012, we recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality.

Loss on Firm Transportation Commitment

We have contractual commitments for certain firm transportation capacity in the Appalachian region that expire in 2022 and, as a result of the recently completed sale of our Appalachian assets, we no longer have production to satisfy these commitments. Accordingly, we recorded a charge of $17.3 million during the third quarter of 2012 representing the liability for estimated discounted future net cash outflows over the remaining term of the contract.

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
	2012			2011			(Unfavorable)			% Change
Interest on borrowings and related fees	$	14,155		$	13,581		$	(574	)	(4	)%
Accretion of original issue discount	351			315			(36		)	(11	)%
Amortization of debt issuance costs	707			747			40			5	%
Capitalized interest	(234		)	(437		)	(203		)	(46	)%
	$	14,979		$	14,206		$	(773	)	(5	)%

The issuance of the 7.25% Senior Notes due 2019, or 2019 Senior Notes, and borrowings under the Revolver, offset by the repurchase of approximately 98% of the 4.50% Convertible Senior Subordinated Notes due 2012, or Convertible Notes, with an effective interest rate of 8.5%, resulted in an approximate $128 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

Table of Contents

Derivatives

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



	Three Months Ended
	September 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Oil and gas derivative unrealized (loss) gain	$	(21,509	)	$	5,686		$	(27,195	)	(478	)%
Oil and gas derivative realized gain	9,238			5,607			3,631			65	%
Interest rate swap unrealized loss	—			(2,715		)	2,715			NM
Interest rate swap realized gain	—			2,920			(2,920		)	(100	)%
	$	(12,271	)	$	11,498		$	(23,769	)	(207	)%

We received cash settlements of $9.2 million during the quarter ended September 30, 2012 and $8.5 million during the comparable period in 2011. The amount received during the 2011 period includes $2.9 million attributable to the termination of an interest rate swap. The significant increase in the unrealized loss on commodity derivatives was due primarily to oil prices increasing above our hedged prices.

Other Income

Other income during the third quarter of 2012 was essentially unchanged as compared to the 2011 period.

Income Tax Benefit

The effective tax benefit rate for the three months ended September 30, 2012 was 40.5% compared to 47.7% for the 2011 period. The income tax benefit for the quarter ended September 30, 2012 includes $2.2 million attributable to a change in the effective state income tax rate due primarily to changes in the number of states in which we will have taxable operations subsequent to the sale of our Appalachian properties.

Table of Contents

Results of Operations

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

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



	Nine Months Ended
	September 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Total production:
Natural gas (MMcf)	16,524			26,646			(10,122		)	(38	)%
Crude oil (MBbl)	1,693			833			860			103	%
NGLs (MBbl)	645			695			(50		)	(7	)%
Total production (MMcfe)	30,551			35,817			(5,266		)	(15	)%
Realized prices, before derivatives:
Natural gas ($/Mcf)	$	2.25		$	4.27		$	(2.02	)	(47	)%
Crude oil ($/Bbl)	102.82			90.33			12.49			14	%
NGLs ($/Bbl)	36.14			48.56			(12.42		)	(26	)%
Total ($/Mcfe)	$	7.68		$	6.22		$	1.46		23	%
Revenues
Natural gas	$	37,098		$	113,660		(76,562		)	(67	)%
Crude oil	174,100			75,278			98,822			131	%
Natural gas liquids (NGLs)	23,298			33,758			(10,460		)	(31	)%
Total product revenues	234,496			222,696			11,800			5	%
Gain on sales of property and equipment, net	2,407			523			1,884			360	%
Other	2,052			2,335			(283		)	(12	)%
Total revenues	238,955			225,554			13,401			6	%
Operating expenses
Lease operating	24,613			29,522			4,909			17	%
Gathering, processing and transportation	11,672			11,261			(411		)	(4	)%
Production and ad valorem taxes	7,915			11,289			3,374			30	%
General and administrative	35,522			38,941			3,419			9	%
Exploration	26,647			68,219			41,572			61	%
Depreciation, depletion and amortization	151,888			113,224			(38,664		)	(34	)%
Impairments	29,316			71,071			41,755			59	%
Loss on firm transportation commitment	17,332			—			(17,332		)	NM
Other	—			300			300			NM
Total operating expenses	304,905			343,827			38,922			11	%
Operating loss	(65,950		)	(118,273		)	52,323			44	%
Other income (expense)
Interest expense	(44,837		)	(41,833		)	(3,004		)	(7	)%
Loss on extinguishment of debt	(3,144		)	(25,403		)	22,259			NM
Derivatives	31,250			19,827			11,423			NM
Other	89			334			(245		)	(73	)%
Loss before income taxes	(82,592		)	(165,348		)	82,756			50	%
Income tax benefit	32,444			60,372			(27,928		)	(46	)%
Net loss	$	(50,148	)	$	(104,976	)	$	54,828		52	%
NM - Not meaningful

Table of Contents

Production

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



Natural gas	Nine Months Ended September 30,		Favorable		Nine Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcf)				(MMcf per day)
Texas	5,294	7,707	(2,413	)	19.3	28.2	(8.9	)	(32	)%
Appalachia	4,654	6,888	(2,235	)	17.0	25.2	(8.2	)	(33	)%
Mid-Continent	2,782	7,022	(4,240	)	10.2	25.7	(15.5	)	(60	)%
Mississippi	3,794	5,029	(1,235	)	13.8	18.4	(4.6	)	(25	)%
	16,524	26,646	(10,122	)	60.3	97.5	(37.2	)	(38	)%



Crude oil	Nine Months Ended September 30,		Favorable		Nine Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)				(MBbl per day)
Texas	1,500.5	500.8	999.6		5.48	1.83	3.65		199	%
Appalachia	0.9	0.3	0.7		—	—	—		NM
Mid-Continent	180.5	317.4	(136.9	)	0.66	1.16	(0.50	)	(43	)%
Mississippi	11.3	14.8	(3.5	)	0.04	0.05	(0.01	)	(20	)%
	1,693.2	833.3	859.9		6.18	3.04	3.14		103	%



NGLs	Nine Months Ended September 30,		Favorable		Nine Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MBbl)				(MBbl per day)
Texas	343.3	374.3	(31.0	)	1.25	1.37	(0.12	)	(9	)%
Appalachia	0.6	0.3	0.3		—	—	—		NM
Mid-Continent	300.8	320.6	(19.8	)	1.10	1.17	(0.07	)	(6	)%
	644.7	695.2	(50.5	)	2.35	2.54	(0.19	)	(7	)%



Combined	Nine Months Ended September 30,		Favorable		Nine Months Ended September 30,		Favorable
	2012	2011	(Unfavorable)		2012	2011	(Unfavorable)		% Change
	(MMcfe)				(MMcfe per day)
Texas	16,357	12,958	3,399		59.7	47.5	12.2		26	%
Appalachia	4,663	6,892	(2,229	)	17.0	25.2	(8.2	)	(33	)%
Mid-Continent	5,670	10,850	(5,180	)	20.7	39.7	(19.0	)	(48	)%
Mississippi	3,862	5,117	(1,256	)	14.1	18.7	(4.6	)	(25	)%
	30,551	35,817	(5,266	)	111.5	131.1	(19.6	)	(15	)%
Certain results in the tables above may not calculate due to rounding.

The decline in total production during the nine months ended September 30, 2012 compared to the corresponding period of 2011 was due primarily to the lack of any significant natural gas drilling since mid-2010 and associated natural production declines as well as the effect of the sale of our Appalachian properties in July 2012 and Arkoma Basin properties in August 2011. The effect of the sale of the Appalachian properties was approximately 1.5 Bcfe and the Arkoma Basin properties was approximately 2.0 Bcfe during the nine month period. The natural declines in production were partially offset by an increase in oil and NGL production attributable to our drilling activity in the Eagle Ford Shale. Approximately 46% of total production on an equivalent basis in the nine months ended September 30, 2012 was attributable to oil and NGLs, a 53% increase over the prior year period. The shift in production mix reflects our focus on emerging oil and NGL-rich plays in the Eagle Ford Shale in South Texas and the Mid-Continent region. During the nine months ended September 30, 2012, our Eagle Ford Shale production of 10.2 Bcfe represented 33% of our total production. We had approximately 2.7 Bcfe of production from this play during the comparable period in 2011.

Table of Contents

Product Revenues and Prices

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



Natural gas	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Mcf)
Texas	$	10,873	$	32,048	$	(21,175	)	$	2.05	$	4.16	$	(2.11	)
Appalachia	11,216		29,066		(17,850		)	2.41		4.22		(1.81		)
Mid-Continent	4,844		30,640		(25,796		)	1.74		4.36		(2.62		)
Mississippi	10,165		21,906		(11,741		)	2.68		4.36		(1.68		)
	$	37,098	$	113,660	$	(76,562	)	$	2.25	$	4.27	$	(2.02	)



Crude oil	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)
								($ per Bbl)
Texas	$	156,093	$	44,859	$	111,234		$	104.03	$	89.57	$	14.46
Appalachia	83		21		62			91.81		83.00		8.81
Mid-Continent	16,732		28,911		(12,179		)	92.68		91.08		1.60
Mississippi	1,192		1,487		(295		)	105.17		100.35		4.82
	$	174,100	$	75,278	$	98,822		$	102.82	$	90.33	$	12.49



NGLs	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)

Texas	$	12,418	$	18,399	$	(5,981	)	$	36.17	$	49.15	$	(12.98	)
Appalachia	31		19		12			50.74		54.76		(4.02		)
Mid-Continent	10,849		15,340		(4,491		)	36.07		47.85		(11.78		)
	$	23,298	$	33,758	$	(10,460	)	$	36.14	$	48.56	$	(12.42	)



Combined	Nine Months Ended September 30,				Favorable			Nine Months Ended September 30,				Favorable
	2012		2011		(Unfavorable)			2012		2011		(Unfavorable)

Texas	$	179,384	$	95,306	$	84,078		$	10.97	$	7.35	$	3.62
Appalachia	11,330		29,106		(17,776		)	2.43		4.22		(1.79		)
Mid-Continent	32,425		74,891		(42,466		)	5.72		6.90		(1.18		)
Mississippi	11,357		23,393		(12,036		)	2.94		4.57		(1.63		)
	$	234,496	$	222,696	$	11,800		$	7.68	$	6.22	$	1.46

As illustrated below, oil production volume coupled with improved oil prices were the significant factors for increasing revenues. The increase was partially offset by lower natural gas and NGL production volumes and prices. Included in the price variance for natural gas was approximately $1.6 million of unfavorable adjustments attributable to the change in prices associated with gas imbalances due to us from partners in our Mid-Continent region. In addition, the sale of our Appalachian assets resulted in a reduction to total revenues of $5.8 million during the nine month period. The following table provides an analysis of the change in our revenues for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011:



	Revenue Variance Due to
	Volume			Price			Total
Natural gas	$	(43,176	)	$	(33,386	)	$	(76,562	)
Crude oil	77,678			21,144			98,822
NGLs	(2,454		)	(8,006		)	(10,460		)
	$	32,048		$	(20,248	)	$	11,800

Table of Contents

Effects of Derivatives

Our oil and gas revenues may change significantly from period to period as a result of changes in commodity prices. As part of our risk management strategy, we use derivative instruments to hedge oil and gas prices. During the nine months ended September 30, 2012 and 2011, we received $22.8 million and $16.5 million in net cash settlements from oil and gas derivatives.

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
	2012		2011		(Unfavorable)			% Change
Natural gas revenues as reported	$	37,098	$	113,660	$	(76,562	)	(67	)%
Cash settlements on natural gas derivatives, net	18,322		16,305		2,017			12	%
Natural gas revenues adjusted for derivatives	$	55,420	$	129,965	$	(74,545	)	(57	)%
Natural gas prices per Mcf, as reported	$	2.25	$	4.27	$	(2.02	)	(47	)%
Cash settlements on natural gas derivatives per Mcf	1.11		0.61		0.50			82	%
Natural gas prices per Mcf adjusted for derivatives	$	3.36	$	4.88	$	(1.52	)	(31	)%
Crude oil revenues as reported	$	174,100	$	75,278	$	98,822		131	%
Cash settlements on crude oil derivatives, net	4,461		179		4,282			(2,392	)%
Crude oil revenues adjusted for derivatives	$	178,561	$	75,457	$	103,104		137	%
Crude oil prices per Bbl, as reported	$	102.82	$	90.33	$	12.49		14	%
Cash settlements on crude oil derivatives per Bbl	2.63		0.21		2.42			(1,152	)%
Crude oil prices per Bbl adjusted for derivatives	$	105.45	$	90.54	$	14.91		16	%

Gain on Sales of Property and Equipment

In July 2012, we recognized a gain of $1.7 million on the sale of our Appalachian assets. In January 2012, we recognized a gain of $0.6 million on the sale of our remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania. In addition, we recognized several individually insignificant gains and losses on the sale of property, equipment, tubular inventory and well materials during both the 2012 and 2011 periods.

Other Income

Other income decreased during the nine months ended September 30, 2012 due primarily to a $1.3 million settlement received in the prior year period from a partner attributable to oil and gas properties that we previously held in the Appalachian region partially offset by higher gathering, transportation and compression fees.

Operating Expenses

Table of Contents

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



	Nine Months Ended
	September 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Lease operating	$	0.81	$	0.82	$	0.01		1	%
Gathering, processing and transportation	0.38		0.31		(0.07		)	(23	)%
Production and ad valorem taxes	0.26		0.32		0.06			19	%
General and administrative excluding share-based compensation and restructuring charges	0.96		0.88		(0.08		)	(9	)%
General and administrative	1.16		1.09		(0.07		)	(6	)%
Depreciation, depletion and amortization	4.97		3.16		(1.81		)	(57	)%

Lease Operating

Lease operating expense decreased on an absolute and unit of production basis during the 2012 period due to lower repair and maintenance expenses and lower compression costs. Certain expense decreases were also attributable to the sale of our Appalachian properties in July 2012 and Arkoma Basin properties in August 2011. Cost decreases were partially offset by higher field contracting, well tending, chemical treatment and environmental compliance costs attributable to our significantly expanded oil drilling program.

Gathering, Processing and Transportation

Gathering, processing and transportation charges increased slightly during the 2012 period, despite lower overall product volume, due primarily to higher processing costs associated with NGLs and a higher amount of unrecovered firm transportation costs in the Appalachian region in 2012 for periods prior to the sale.

Production and Ad Valorem Taxes

Production and ad valorem taxes decreased during the 2012 period due primarily to Oklahoma severance tax rebates of $2.8 million attributable to horizontal and ultra-deep wells for the period of July 1, 2009 through June 30, 2011. Rebates were also recognized for certain Texas wells. Production taxes also decreased due to the Appalachian asset sale as well as lower overall natural gas volumes and prices in the 2012 period as compared to the 2011 period. The decrease in the 2012 period was partially offset by the effect of a property tax recovery in the 2011 period attributable to wells located in West Virginia. As a percentage of product revenue, production and ad valorem taxes decreased to 3.3% during the 2012 period from 5.1% during the 2011 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
	2012		2011		(Unfavorable)			% Change
Recurring general and administrative expenses	$	29,216	$	31,689	$	2,473		8	%
Share-based compensation (liability-classified)	790		—		(790		)	NM
Share-based compensation (equity-classified)	4,233		5,629		1,396			25	%
Restructuring expenses	1,283		1,623		340			21	%
	$	35,522	$	38,941	$	3,419		9	%

Table of Contents

based performance metrics. Equity-classified share-based compensation charges attributable to stock options and restricted stock units, which represent non-cash expenses, decreased during the 2012 period due primarily to a lower number of awards granted. Restructuring expenses for both the 2012 and 2011 periods include termination benefits and office relocation costs. The 2012 charge includes a provision for lease costs associated with our Canonsburg, Pennsylvania office as well as an adjustment to the lease obligation for our former Tulsa, Oklahoma office due to a change in estimated sub-lease rental income.

Exploration

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



	Nine Months Ended
	September 30,				Favorable
	2012		2011		(Unfavorable)		% Change
Unproved leasehold amortization	$	24,765	$	33,593	$	8,828	26	%
Dry hole costs	—		18,864		18,864		100	%
Geological and geophysical costs	441		9,036		8,595		95	%
Drilling rig charges	—		4,778		4,778		100	%
Other, primarily delay rentals	1,441		1,948		507		26	%
	$	26,647	$	68,219	$	41,572	61	%

Unproved leasehold amortization declined during the 2012 period as certain properties in the Eagle Ford and Marcellus Shales were transferred to proved in the second half of 2011 and the first half of 2012. The prior year period included dry hole costs attributable to certain unsuccessful wells in the Mid-Continent region. In addition, geological and geophysical costs decreased during the 2012 period because our efforts in that period were concentrated in the Eagle Ford Shale whereas in the prior year period we conducted exploratory prospect activities in multiple areas. The 2011 period also includes rig-related charges we incurred in connection with the 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
	2012		2011		(Unfavorable)			% Change
Depletion	$	148,585	$	109,195	$	(39,390	)	(36	)%
Depreciation	2,997		3,662		665			18	%
Amortization	306		367		61			17	%
	$	151,888	$	113,224	$	(38,664	)	(34	)%



	DD&A Variance Due to
	Production		Rates			Total
Nine months ended September 30, 2012 compared to 2011	$	16,645	$	(55,309	)	$	(38,664	)

The effect of lower overall production volumes on DD&A was more than offset by higher depletion rates associated with oil and NGL production. Our average depletion rate increased to $4.86 per Mcfe for the 2012 period from $3.05 per Mcfe for the 2011 period due primarily to higher capitalized finding and development costs attributable to our oil wells in the Eagle Ford Shale and to a lesser extent negative reserve revisions of our natural gas assets.

Table of Contents

Impairments

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



	Nine Months Ended
	September 30,				Favorable
	2012		2011		(Unfavorable)			% Change
Oil and gas properties	$	28,481	$	71,071	$	42,590		60	%
Other	835		—		(835		)	NM
	$	29,316	$	71,071	$	41,755		59	%

In September 2012, we recognized an impairment of certain tubular inventory and well materials triggered primarily by declines in asset quality. In June 2012, we recognized an impairment of our Appalachian assets triggered by the expected disposition of these properties in the third quarter of 2012. In 2011, we recognized an impairment of our Arkoma Basin assets triggered by the expected disposition of these natural gas properties in the third quarter of 2011.

Loss on Firm Transportation Commitment

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:



	Nine Months Ended
	September 30,						Favorable
	2012			2011			(Unfavorable)			% Change
Interest on borrowings and related fees	$	42,461		$	37,448		$	(5,013	)	(13	)%
Accretion of original issue discount	1,025			3,103			2,078			67	%
Amortization of debt issuance costs	2,083			2,709			626			23	%
Capitalized interest	(732		)	(1,427		)	(695		)	(49	)%
	$	44,837		$	41,833		$	(3,004	)	(7	)%

The issuance of the 2019 Senior Notes and borrowings under the Revolver, offset by the repurchase of approximately 98% of the Convertible Notes with an effective interest rate of 8.5%, resulted in an approximate $184 million higher weighted-average balance of debt outstanding during the 2012 period compared to the 2011 period. Accordingly, interest expense increased due to a higher average outstanding principal balance despite lower effective interest rates attributable to the 2019 Senior Notes and Revolver.

Loss on Extinguishment of Debt

When we entered into the Revolver in September 2012, we expensed issuance costs of $3.2 million attributable to our previous revolving credit facility. During the prior year period, we recognized $1.2 million attributable to the issuance of our previous revolving credit facility and a change in the composition of the bank syndicate. 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

Table of Contents

was comprised of the excess of cash paid for the liability component over the carrying value, plus the write-off of a pro rata share of debt issuance costs and incremental fees paid in cash.

Derivatives

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



	Nine Months Ended
	September 30, 2012					Favorable
	2012		2011			(Unfavorable)			% Change
Oil and gas derivative unrealized gain (loss)	$	7,061	$	2,114		$	4,947		234	%
Oil and gas derivative realized gain	22,783		16,484			6,299			38	%
Interest rate swap unrealized gain	—		(2,589		)	2,589			NM
Interest rate swap realized gain	1,406		3,818			(2,412		)	(63	)%
	$	31,250	$	19,827		$	11,423		58	%

We received cash settlements of $24.2 million during the nine months ended September 30, 2012 and $20.3 million during the comparable period in 2011. The cash settlements in the 2012 and 2011 periods included $1.2 million and $2.9 million attributable to the termination of our interest rate swap agreements during those periods. The increase in the unrealized gain on commodity derivatives was due primarily to oil and natural gas prices declining below our hedged prices.

Other

Other income decreased during the 2012 period due primarily to lower interest income earned on average cash balances.

Income Tax Benefit

The effective tax rate for the nine months ended September 30, 2012 was 39.3% compared to 36.5% for the 2011 period. The income tax benefit for the nine months ended September 30, 2012 includes $2.2 million attributable to a change in the effective state income tax rate due primarily to changes in the composition of states in which we will have taxable operations subsequent to the sale of our Appalachian properties.

Table of Contents

Liquidity and Capital Resources

Sources of Liquidity

We are currently meeting our cash requirements with a combination of operating cash flows and cash on hand. We have no debt maturities until 2016. Our business strategy requires capital expenditures in excess of our operating cash flows for the remainder of 2012 and 2013. 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 capital program for the remainder of 2012 and 2013 with operating cash flows, cash on hand and borrowings under the Revolver.

We used the proceeds from the sale of our Appalachian properties as well as a recently received federal income tax refund to pay down a substantial portion of borrowings outstanding under our previous revolving credit facility. In October 2012, we used the proceeds from our combined common and preferred stock offerings to pay down the remaining balance under the Revolver. In addition, we recently discontinued our common stock dividend, which improved our liquidity by increasing available cash flows by approximately $10 million per year. As of October 26, 2012, we have the entire $300 million commitment of the Revolver, excluding $1.6 million of outstanding letters of credit, available to us as well as approximately $50 million of cash on hand. In view of our recent actions, we believe that we will have sufficient liquidity in 2013 to fund our capital programs.

In September 2012, we entered into the Revolver which replaced our previous revolving credit facility that was entered into in August 2011. The Revolver provides for a $300 million revolving commitment, including a $20 million sublimit for the issuance of letters of credit. The Revolver has an accordion feature that allows us to increase the commitment by up to an aggregate of $300 million upon receiving additional commitments from one or more lenders. The Revolver is governed by a borrowing base calculation, and availability under the Revolver may not exceed the lesser of the aggregate commitments and the borrowing base. The initial borrowing base under the Revolver is $300 million and will be re-determined based on a semi-annual review of our total proved oil, NGL and natural gas reserves starting in the spring of 2013. The Revolver is available to us for general purposes including working capital, capital expenditures and acquisitions. The Revolver matures in September 2017. As of October 26, 2012, we had no outstanding borrowings under the Revolver and outstanding letters of credit were $1.6 million.

The following table summarizes our borrowing activity under the Revolver and our previous revolving credit facility during the periods presented:



	Borrowings Outstanding
	Weighted- Average		Maximum		Weighted- Average Rate
Three Months Ended September 30, 2012	$	128,424	$	190,000	2.1919	%
Nine Months Ended September 30, 2012	$	131,303	$	190,000	2.1296	%

Our revenues are subject to significant volatility as a result of changes in commodity prices. Accordingly, 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 typically through the use of collar, swap and swaption contracts. The level of our hedging activity and duration of the instruments employed depend on our cash flow at risk, available hedge prices and our operating strategy. During the nine months ended September 30, 2012, our commodity derivatives portfolio provided $4.5 million of cash inflows related to lower than anticipated prices received for our oil production and $18.3 million of cash inflows attributable to lower than anticipated prices received for our natural gas production.

For the remainder of 2012, we have hedged approximately 68 percent of our estimated crude oil production, at a weighted average floor/swap and ceiling prices of between $100.80 and $102.55 per barrel. In addition, we have hedged approximately 24 percent of our estimated natural gas production for the remainder of 2012, at weighted average swap price of $5.10 per MMBtu .

Table of Contents

Cash Flows

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



	Nine Months Ended
	September 30,
	2012			2011			Variance
Cash flows from operating activities	$	190,214		$	103,164		$	87,050
Cash flows from investing activities
Capital expenditures - property and equipment	(257,194		)	(318,274		)	61,080
Proceeds from sales of property and equipment and other, net	93,456			31,177			62,279
Net cash used in investing activities	(163,738		)	(287,097		)	123,359
Cash flows from financing activities
Dividends paid	(5,176		)	(7,736		)	2,560
Proceeds from revolving credit facility borrowings, net	(22,000		)	15,000			(37,000		)
Proceeds from issuance of senior notes	—			300,000			(300,000		)
Repurchase of Convertible Notes	—			(232,963		)	232,963
Debt issuance costs paid	(1,779		)	(8,850		)	7,071
Other, net	—			1,148			(1,148		)
Net cash (used in) provided by financing activities	(28,955		)	66,599			(95,554		)
Net decrease in cash and cash equivalents	$	(2,479	)	$	(117,334	)	$	114,855

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, 2011	$	103,164
Variances due to:
Effect of higher operating margins, net of working capital changes	57,004
Higher income tax refunds received in 2012	33,007
Higher settlements from commodity derivatives portfolio	6,299
Transaction costs paid in connection with extinguishment of debt in 2011	2,433
Higher interest payments, net of interest rate swap settlements	(10,577		)
Higher restructuring and exit cost payments in 2012	(1,116		)
Cash flows from operating activities for the nine months ended September 30, 2012	$	190,214

Due primarily to the realization of higher net margins on our expanding crude oil production as well as the receipt of a federal income tax refund, our cash flows from operating activities improved significantly during the 2012 period as compared to the 2011 period. During the 2012 period, we realized higher settlements from our commodity derivatives portfolio as compared to the 2011 period, due primarily to lower natural gas prices partially offset by a lower overall hedged production volume. We paid higher amounts for interest during the 2012 period due to higher average outstanding debt balances. In addition, our sources from working capital were higher during the 2012 period due primarily to the timing of collections and disbursements and lower compensation-related costs paid in the 2012 period. The 2011 period included transaction costs paid in connection with the repurchase of our Convertible Notes as well as the issuance of our previous revolving credit facility.

Cash Flows From Investing Activities

Capital expenditures were lower during the 2012 period due primarily to our focus on Eagle Ford Shale drilling. During the prior year period, we acquired significant acreage in the Eagle Ford Shale and had a more extensive capital program in the Mid-Continent region.

Table of Contents

Proceeds from sales of non-core properties and other assets were received during both the 2012 and 2011 periods. The amounts received during the 2012 period are primarily attributable to the sale of our Appalachian properties and remaining undeveloped acreage in Butler and Armstrong counties in Pennsylvania. The amounts received during the 2011 period are primarily attributable to the sale of our Arkoma Basin properties. Both periods include the receipt of insurance proceeds attributable to damages from a fire at one of our warehouse facilities in early 2011.

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



	Nine Months Ended
	September 30,
	2012		2011
Oil and gas:
Development drilling	$	188,071	$	207,887
Exploration drilling	47,365		53,247
Seismic	441		9,036
Lease acquisitions, field projects and other	17,341		46,393
Pipeline and gathering facilities	13,310		6,273
	266,528		322,836
Other - Corporate	490		1,163
	$	267,018	$	323,999

The following table reconciles the total costs of 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,
	2012			2011
Total capital program costs	$	267,018		$	323,999
Less:
Exploration expenses
Seismic	(441		)	(9,036		)
Other, primarily delay rentals	(1,417		)	(1,948		)
Transfers from tubular inventory and well materials	(12,420		)	(1,954		)
Changes in accrued capitalized costs	652			5,686
Add:
Tubular inventory and well materials purchased in advance of drilling	3,067			—
Capitalized interest	732			1,427
Other	3			100
Total cash paid for capital expenditures	$	257,194		$	318,274

Cash Flows From Financing Activities

Cash used in financing activities during the 2012 period included net repayments of borrowings under the Revolver while activity during the 2011 period included the effect of issuing the 2019 Senior Notes offset by the repurchase of a substantial portion of the Convertible Notes as well as initial borrowings under our previous revolving credit facility. Both periods include the payment of debt issuance costs and dividend payments on common stock, and the 2011 period includes proceeds received from the exercise of stock options by employees. In August 2012, we eliminated our common stock dividend.

Table of Contents

Financial Condition

As of October 26, 2012, we had approximately $50 million of cash on hand and $298.4 million of unused borrowing capacity under the Revolver. The borrowing capacity is determined by reducing the borrowing base commitment of $300 million by outstanding letters of credit of $1.6 million.

Credit Facility, Debt and Preferred Stock

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



	September 30, 2012			December 31, 2011
Revolving credit facility	$	77,000		$	99,000
Senior notes due 2016, net of discount (principal amount of $300,000)	294,447			293,561
Senior notes due 2019	300,000			300,000
Convertible notes due 2012, net of discount (principal amount of $4,915)	4,884			4,746
	676,331			697,307
Less: Current portion of long-term debt	(4,884		)	(4,746		)
	$	671,447		$	692,561

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 charged at 0.375% to 0.500% on the undrawn portion of the Revolver depending on our ratio of outstanding borrowings to the available Revolver capacity. As of September 30, 2012, the actual interest rate on the borrowings under the Revolver was 4.0%. This rate represents the prime rate option which applied to the initial borrowings through October 3, 2012 at which time the Adjusted LIBOR interest rate went into effect. The Adjusted LIBOR margin applicable to the initial borrowings subsequent to the conversion from the prime rate option was 1.75%.

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.

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.

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 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

Table of Contents

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, we repurchased $225.1 million aggregate principal amount of the Convertible Notes for $233.0 million, including 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 offering. Subsequent to the tender offer, a total of $4.9 million aggregate principal amount of Convertible Notes remains outstanding. The remaining unamortized discount will be amortized through November 2012.

6% Preferred Stock. Each depositary share of the 6% Preferred Stock has a liquidation preference of $100.00 per share and is entitled to an annual dividend of $6.00 payable quarterly on January 15, April 15, July 15 and October 15 of each year in cash, common stock or a combination thereof. Each depositary share of the 6.00% Preferred Stock is convertible at the option of the holder at an initial conversion rate of 16.6667 shares of our common stock per depositary share, or $6.00 per share of common stock. The conversion price represents a premium of 20 percent relative to the common stock offering price of $5.00 per share. The 6% Preferred Stock is not redeemable by us at any time. On or after October 15, 2017, we may cause all or a portion of the depositary shares of the 6% Preferred Stock to be automatically converted into shares of our common stock at the then-applicable conversion rate if certain conditions are met.

Our 6% Preferred Stock, with respect to dividend rights and rights upon our liquidation, winding-up or dissolution, will rank senior to our common stock and to all of our other capital stock issued in the future unless the terms of that stock expressly provide otherwise.

Covenant Compliance

The 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 for periods through December 31, 2013, 4.25 through June 30, 2014 and 4.00 through maturity in 2017. 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 Revolver.

As of September 30, 2012 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, 2012:



Description of Covenant	Required Covenant	Actual Results
Total debt to EBITDAX	< 4.5 to 1	2.8 to 1
Current ratio	> 1.0 to 1	2.5 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 our 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.

Table of Contents

Future Capital Needs and Commitments

In 2012, we anticipate making capital expenditures, excluding any additional acquisitions, of up to approximately $350 million. The capital expenditures for the remainder of 2012 will be funded primarily by operating cash flows, cash on hand and borrowings 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 2012, we expect to allocate capital expenditures as follows: Eagle Ford Shale (approximately 90 percent), Mid-Continent region (approximately six percent) and all other areas (approximately four percent). This allocation includes approximately 86 percent for development and exploratory drilling, 8 percent for leasehold acquisition and 6 percent for seismic and other projects. We anticipate that we will allocate substantially all of our 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 which are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as plugging of abandoned wells. As of September 30, 2012, we had recorded asset retirement obligations of $4.5 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, including any significant limitation on the use of hydraulic fracturing, have the potential to adversely affect our operations.

Critical Accounting Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting estimates that involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2011. The following development is discussed with respect to its applicability during the nine months ended September 30, 2012 and future periods.

Share-Based Compensation

In February 2012, we granted PBRSUs to certain executive officers. Vested PBRSUs are payable in cash on the third anniversary of the date of grant based upon the achievement of certain market-based performance metrics with respect to each of a one-year, two-year and three-year performance period, in each case commencing on the date of grant. The number of PBRSUs vested can range from 0% to 200% of the initial grant. The PBRSUs do not have voting rights and do not participate in dividends.

Because the PBRSUs are payable in cash, they are considered liability-classified awards and are included in the Other liabilities caption on our Condensed Consolidated Balance Sheets. Compensation cost associated with the PBRSUs is measured at the end of each reporting period based on the fair value derived from a Monte Carlo model and recognized based on the period of time that has elapsed during each of the individual performance periods. The Monte Carlo model is a binomial valuation model that requires significant judgment with respect to certain assumptions including volatility, dividends and other factors. Due primarily to the sensitivity of certain model assumptions as well as the inherent variability of modeling market-based performance over future periods, our compensation expense with respect to the PBRSUs can be volatile. As an

Table of Contents

illustration, the expense attributable to the PBRSUs during the three months ended June 30, 2012 was $0.6 million while the expense during the three months ended September 30, 2012 was less than $0.2 million.

New Accounting Standards

Table of Contents


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.

Interest Rate Risk

All of our long-term debt instruments, with the exception of the Revolver, have fixed interest rates. Accordingly, our interest rate risk is attributable to our borrowings under the Revolver which is subject to variable interest rates. As of September 30, 2012, we had borrowings of $77 million outstanding under the Revolver at an effective interest rate of 4.0000%. Assuming a constant borrowing level of $77 million under the Revolver, an increase (decrease) in the interest rate of one percent would result in an increase (decrease) in interest expense of approximately $0.8 million on an annual basis.

Commodity Price Risk

We produce and sell crude oil, NGLs and natural gas. 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 collars, swaps and swaptions) to seek to mitigate the price risks associated with fluctuations in crude oil, NGLs and natural gas 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 crude oil, NGLs and natural gas.

During the nine months ended September 30, 2012, we reported net commodity derivative income of $31.3 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 crude oil, NGLs and natural gas 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.

Table of Contents

The following table lists our commodity derivative positions and their fair values as of September 30, 2012:



		Average Volume Per Day	Weighted Average Price				Fair Value
	Instrument	Average Volume Per Day	Floor/Swap		Ceiling		Asset		Liability
Natural Gas:		(in MMBtu)	($/MMBtu)
Fourth quarter 2012	Swaps	10,000	$	5.10			$	1,636	$	—
Crude Oil:		(barrels)	($/barrel)
Fourth quarter 2012	Collars	1,000	$	90.00	$	97.00	52		—
First quarter 2013	Collars	1,000	$	90.00	$	100.00	105		—
Second quarter 2013	Collars	1,000	$	90.00	$	100.00	93		—
Third quarter 2013	Collars	1,000	$	90.00	$	100.00	124		—
Fourth quarter 2013	Collars	1,000	$	90.00	$	100.00	161		—
Fourth quarter 2012	Swaps	3,000	$	104.40			3,211		—
First quarter 2013	Swaps	2,250	$	103.51			1,954		—
Second quarter 2013	Swaps	2,250	$	103.51			1,912		—
Third quarter 2013	Swaps	1,500	$	102.77			1,230		—
Fourth quarter 2013	Swaps	1,500	$	102.77			1,294		—
First quarter 2014	Swaps	2,000	$	100.44			1,406		—
Second quarter 2014	Swaps	2,000	$	100.44			1,540		—
Third quarter 2014	Swaps	1,500	$	100.20			1,218		—
Fourth quarter 2014	Swaps	1,500	$	100.20			1,274		—
First quarter 2013	Swaption	1,100	$	100.00			—		299
Second quarter 2013	Swaption	1,000	$	100.00			—		267
Third quarter 2013	Swaption	900	$	100.00			—		203
Fourth quarter 2013	Swaption	750	$	100.00			—		133
First quarter 2014	Swaption	812	$	100.00			—		386
Second quarter 2014	Swaption	812	$	100.00			—		386
Third quarter 2014	Swaption	812	$	100.00			—		386
Fourth quarter 2014	Swaption	812	$	100.00			—		386
Settlements to be received in subsequent period							886		—

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 oil and gas 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	$	(0.6	)	$	0.6
Effect on the fair value of crude oil derivatives	$	(24.3	)	$	20.3
Effect on 2012 operating income, excluding natural gas derivatives	$	2.5		$	(2.5	)
Effect on 2012 operating income, excluding crude oil derivatives	$	5.4		$	(5.4	)

Table of Contents


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, 2012. 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, 2012, 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.

Table of Contents

PART II. OTHER INFORMATION

Item 6 Exhibits



2.1	Purchase and Sale Agreement dated July 16, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on July 18, 2012).

2.1.1	Amendment and Supplement to Purchase and Sale Agreement, dated July 31, 2012, by and among Penn Virginia Oil & Gas Corporation, EnerVest Energy Institutional Fund XII-A, L.P., EnerVest Energy Institutional Fund XII-WIB, L.P. and EnerVest Energy Institutional Fund XII-WIC, L.P. (incorporated by reference to Exhibit 2.1 to Registrant's Current Report on Form 8-K filed on August 2, 2012).

3.1	Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1999).

3.1.1	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant's Annual Report on Form 10-K for the year ended December 31, 1999).

3.1.2	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3 to Registrant's Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2004).

3.1.3	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3 to Registrant's Current Report on Form 8-K filed on June 12, 2007).

3.1.4	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3 to Registrant's Current Report on Form 8-K filed on May 10, 2010).

3.1.5	Articles of Amendment of Articles of Incorporation of Penn Virginia Corporation (incorporated by reference to Exhibit 3.1 to Registrant's Current Report on Form 8-K filed on October 17, 2012).

3.2	Amended and Restated Bylaws of Penn Virginia Corporation (incorporated by reference to Exhibit 3.2 to Registrant's Current Report on Form 8-K filed on October 17, 2012).

4.1	Deposit Agreement, dated October 17, 2012, among Penn Virginia Corporation, American Stock Transfer & Trust Company, LLC and the holders from time to time of the depositary shares described therein (incorporated by reference to Exhibit 4.1 to Registrant's Current Report on Form 8-K filed on October 17, 2012).

4.2	Form of depositary receipt representing the Depositary Shares (included as Exhibit A to Exhibit 4.1)(incorporated by reference to Registrant's Current Report on Form 8-K filed on October 17, 2012).

10.1	Confidential Severance Agreement and Release dated August 31, 2012 by and between Penn Virginia Corporation and Michael E. Stamper (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on September 5, 2012).

10.2	Credit Agreement dated as of September 28, 2012 among Penn Virginia Holding Corp., as borrower, Penn Virginia Corporation, as parent, the lenders party thereto and Wells Fargo Bank, National Association, as administrative agent (incorporated by reference to Exhibit 10.1 to Registrant's Current Report on Form 8-K filed on October 2, 2012).

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

Table of Contents



Item 6 Exhibits (continued)

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

Table of Contents

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 1, 2012	By:	/s/ Steven A. Hartman
		Steven A. Hartman
		Senior Vice President and Chief Financial Officer

Date: November 1, 2012	By:	/s/ Joan C. Sonnen
		Joan C. Sonnen
		Vice President and Controller