Unassociated Document

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

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

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

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

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

Gain on Sales of Property and Equipment

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

Other Income

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

Operating Expenses

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

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

Lease Operating

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

Gathering, Processing and Transportation

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

Production and Ad Valorem Taxes

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

General and Administrative

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

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

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

Exploration

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

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

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

Depreciation, Depletion and Amortization (DD&A)

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

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

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

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

Impairments

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

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

During the quarter ended June 30, 2011, we recognized an impairment of our Arkoma Basin assets which was triggered by the expected disposition of these high-cost gas properties. The sale was completed in August 2011. During the prior year period, we recognized impairment charges with respect to certain coal bed methane properties in the Mid-Continent region due to market declines in spot and future oil and gas prices. We also recorded impairment charges attributable to certain tubular inventory and well materials triggered primarily by declines in asset quality.

Other

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

Interest Expense

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

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

The issuance of the 2019 Senior Notes at 7.25% and borrowings under the Revolver, offset by the repurchase of approximately 98% of the outstanding Convertible Notes with an effective interest rate at 8.5%, added approximately $108 million to the net principal amount of debt outstanding. Accordingly, interest expense increased due to higher average amounts of debt outstanding partially offset by lower effective interest rates. Capitalized interest was higher during the 2010 period due to higher carrying values on eligible capital projects.

Loss on Extinguishment of Debt

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

Derivatives

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

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

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

Other

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

Income Tax Expense

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

Discontinued Operations

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

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

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

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

Gain on Sale of Discontinued Operations

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

Liquidity and Capital Resources

Sources of Liquidity

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

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

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

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

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

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

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

Cash Flows

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

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

Cash Flows From Operating Activities

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

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

Cash Flows From Investing Activities

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

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

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

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

	Nine Months Ended September 30,
	2011			2010
Total capital program costs	$	323,999		$	342,610
Less:
Exploration expenses
Seismic		(9,036	)		(8,573	)
Other, primarily delay rentals		(1,948	)		(2,213	)
Other		(1,954	)		-
Changes in accrued capitalized costs		5,686			(11,065	)
Property received as consideration in sale transaction 1		-			(8,204	)
Add:
Capitalized interest		1,427			1,155
Other		100			-
Total cash paid for capital expenditures	$	318,274		$	313,710

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

Cash Flows From Financing Activities

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

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

Financial Condition

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

Credit Facility and Debt

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

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

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

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

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

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

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

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

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

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

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

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

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

Covenant Compliance

Our Revolver requires us to maintain certain financial covenants as follows:

Total debt to EBITDAX, each as defined in the Revolver, for any four consecutive quarters may not exceed 4.5 to 1.0 reducing to 4.0 to 1.0 for periods ending after June 30, 2013. EBITDAX, which is a non-GAAP measure, generally means net income plus interest expense, taxes, depreciation, depletion and amortization expenses, exploration expenses, impairments and other non-cash charges or losses.

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

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

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

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

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

Future Capital Needs and Commitments

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

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

Environmental Matters

Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations including the plugging of abandoned wells. As of September 30, 2011, we have outstanding asset retirement obligations of approximately $6.0 million attributable to these activities. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material impact on our financial condition or results of operations. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations. See Item 1A Risk Factors.

Critical Accounting Estimates

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

New Accounting Standards

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

Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are interest rate risk and commodity price risk. Our interest rate risk is attributable to our borrowings under the Revolver at variable interest rates. A change in interest rates of one percent on our outstanding Revolver borrowings as of September 30, 2011 would result in a change in interest expense of approximately $0.2 million on an annual basis.

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

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

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

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

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

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

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

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

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of September 30, 2011. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of September 30, 2011, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1A Risk Factors

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

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

Item 6 Exhibits

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

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

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

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

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

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

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

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

101.INS	XBRL Instance Document

101.SCH	XBRL Taxonomy Extension Schema Document

101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document

101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

101.LAB	XBRL Taxonomy Extension Label Linkbase Document

101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document

SIGNATURES

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

		PENN VIRGINIA CORPORATION

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

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

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

Large accelerated filer	x	Accelerated filer	¨

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

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

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

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

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

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

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

Commitments and contingencies (Note 10)

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

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

Item		Page
	Part I - Financial Information

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

Forward-Looking Statements		17

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

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

3.	Quantitative and Qualitative Disclosures About Market Risk	39

4.	Controls and Procedures	40

	Part II - Other Information

1A.	Risk Factors	41

6.	Exhibits	42

Signatures		43

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

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

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

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

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

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

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

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

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

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

	Penn Virginia			Noncontrolling
	Corporation			Interests in			Total
	Shareholders'			Discontinued			Shareholders'			Comprehensive
	Equity			Operations			Equity			Income (Loss)
Balance as of December 31, 2010	$	980,276		$	-		$	980,276
Dividends paid ($0.16875 per share)		(7,736	)		-			(7,736	)
Other changes to shareholders' equity		6,697			-			6,697
Comprehensive income:
Net loss		(104,976	)		-			(104,976	)	$	(104,976	)
Other, net of tax		102			-			102			102
Balance as of September 30, 2011	$	874,363		$	-		$	874,363		$	(104,874	)
Balance as of December 31, 2009	$	908,088		$	329,911		$	1,237,999
Dividends paid ($0.16875 per share)		(7,700	)		-			(7,700	)
Distributions to noncontrolling interest holders		-			(49,566	)		(49,566	)
Sale of PVG units, net of tax		82,102			70,188			152,290
Deconsolidation of PVG		-			(382,324	)		(382,324	)
Other changes to shareholders' equity		6,061			3,119			9,180
Comprehensive income:
Net income		14,514			28,090			42,604		$	42,604
Hedging reclassification adjustment		-			582			582			582
Other, net of tax		(174	)		-			(174	)		(174	)
Balance as of September 30, 2010	$	1,002,891		$	-		$	1,002,891		$	43,012

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

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

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