8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 8-K

CURRENT REPORT

PURSUANT TO SECTION 13 OR 15(D)

OF THE SECURITIES EXCHANGE ACT OF 1934

Date of Report: November 1, 2006

(Date of Earliest Event Reported)

PENN VIRGINIA CORPORATION

(Exact Name of Registrant as Specified in its Charter)

Virginia	1-13283	23-1184320
(State or Other Jurisdiction of Incorporation)	(Commission File Number)	(IRS Employer Identification No.)

Three Radnor Corporate Center, Suite 300, 100 Matsonford Road, Radnor, Pennsylvania	19087
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code: (610) 687-8900

(Former Name, Former Address, and Former Fiscal Year, If Changed Since Last Report)

Check the appropriate box below if the form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)

Item 2.02. Results of Operations and Financial Conditions.

And

Item 7.01. Regulation FD Disclosure

On November 1, 2006, Penn Virginia Corporation issued a press release regarding its financial results for the three months ended September 30, 2006. A copy of this earnings press release is furnished as Exhibit 99 to this Report.

The non-generally accepted accounting principle financial measure of operating cash flow is presented in our earnings release. The amounts included in the calculation of this measure are computed in accordance with generally accepted accounting principles (“GAAP”). As part of our press release information, we have provided reconciliations of this non-GAAP financial measure to its most comparable financial measure or measures calculated and presented in accordance with GAAP.

We believe that investors can more accurately understand our financial results if they have access to the same financial measures used by management. Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under GAAP. Management believes that operating cash flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities, service debt and pay dividends. This measure is widely used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity, or as an alternative to net income.

In accordance with General Instruction B.2 of Form 8-K, the above information is being furnished under Items 2.02 and 7.01 of Form 8-K and is not deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934, or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934.

Item 9.01. Financial Statements and Exhibits.

(d) Exhibits

99 - Penn Virginia Corporation press release dated November 1, 2006.

Exhibit 99 and the information included in it shall not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 or incorporated by reference in any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934, except as may be expressly set forth by specific reference in this Report.

SIGNATURES

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

Date: November 2, 2006

Penn Virginia Corporation
By:	/s/ Frank A. Pici
	Frank A. Pici
	Executive Vice President and Chief Financial Officer

3

Exhibit Index

Exhibit No.	Description
99	Penn Virginia Corporation press release dated November 1, 2006

4

EX-99

Exhibit 99

Penn Virginia Corporation

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

FOR IMMEDIATE RELEASE

Contact:	Frank A. Pici, Executive Vice President and Chief Financial Officer
	Ph: (610) 687-8900 Fax: (610) 687-3688 E-Mail: invest@pennvirginia.com

PENN VIRGINIA CORPORATION

ANNOUNCES THIRD QUARTER 2006 RESULTS

RADNOR, PA (BusinessWire) November 1, 2006 – Penn Virginia Corporation (NYSE: PVA) today reported third quarter 2006 net income of $22.9 million, or $1.21 per diluted share, compared to $20.0 million, or $1.07 per diluted share, for the third quarter of 2005. For the third quarter of 2006, operating income was $44.6 million, compared to third quarter 2005 operating income of $46.8 million. Operating cash flow, a non-GAAP measure, was $66.6 million for the third quarter of 2006, compared to $67.3 million for the third quarter of 2005. The increase in net income was due to higher operating income from the Company’s ownership in Penn Virginia Resource Partners, L.P. (NYSE: PVR), which is reported under the coal and natural gas midstream segments below, and derivative gains. These increases were offset in part by higher expenses in the oil and gas segment due to higher production and increased interest expense due to increased debt and higher prevailing interest rates. A reconciliation of non-GAAP financial measures appears in the financial tables later in this release.

Net income for the nine months ended September 30, 2006 was $65.2 million, or $3.46 per diluted share, compared to $34.7 million, or $1.85 per diluted share, for the nine months ended September 30, 2005. Operating cash flow, a non-GAAP measure, was $198.0 million for the nine months ended September 30, 2006, or 21 percent above the $164.0 million for the nine months ended September 30, 2005.

Management Comment

A. James Dearlove, President and Chief Executive Officer, said, “Natural gas and oil production for the third quarter of 2006 was a new quarterly record, approximately 15 percent over the corresponding quarter in 2005 and up six percent over the second quarter of 2006. Natural gas prices for the quarter declined relative to the third quarter of 2005, however, our hedging program allowed us to offset some of that decline.

“Operationally, we were very active during the third quarter, drilling 54 development wells. In the east Texas Cotton Valley program, we drilled 19 successful development wells and we continue to test deeper intervals in both our 100 percent working interest area and in our joint venture area. Horizontal drilling techniques are being tested by us and our joint venture partner, GMX Resources Inc. (NASDAQ: GMXR). In the fourth quarter of 2006, we expect to add another drilling rig to the four rigs currently drilling in the area. Also, in the fourth quarter we expect to continue our Cotton Valley lease acquisition effort. In our Mississippi Selma Chalk play, we drilled 21 successful development wells and we are adding acreage when available. In the fourth quarter of 2006, we plan to drill wells to test down-spacing and horizontal drilling as ways to enhance play economics. We drilled four successful horizontal coalbed

methane (HCBM) wells in our Appalachian drilling program. Drilling activity commenced in our Arkoma Basin HCBM program in Oklahoma, where we drilled five successful wells during the third quarter of 2006, and anticipate drilling a total of 30 HCBM wells in that area by year-end using two drilling rigs. We also expect to drill two Granite Wash wells in western Oklahoma during the fourth quarter. We continue to seek non-conventional resource plays such as CBM and shale to expand our prospect inventory and take advantage of our in-house expertise.

“PVR’s record operating income in the third quarter of 2006 was a result of commodity prices and the contribution of our acquisitions in 2005 and 2006. Coal prices continued to be strong and we enjoyed increased production from our coal properties. Natural gas processing margins were elevated by historical standards as natural gas liquids prices were strong relative to natural gas prices.

“The strong performance in both of our businesses was the impetus for PVR’s recently announced distribution increase to $0.40 per unit or $1.60 per unit on an annualized basis. Despite the volatility in commodity prices, we are confident that PVR’s diversified portfolio of high quality assets will provide more than adequate cash flows to support this and future distribution increases. As the owner of PVR’s incentive distribution rights, we have the right to receive 50 percent of any future cash distribution increases above $1.50 per unit, with the limited partners receiving the other 50 percent.

“On July 11, 2006, we announced that our wholly owned subsidiary, Penn Virginia GP Holdings, L.P. (PVG), which was formed to own the general partner interest, all of the incentive distribution rights, 7,475,414 common units and 7,649,880 subordinated units in PVR, had filed a registration statement with the Securities and Exchange Commission for an initial public offering of six million of its common units representing limited partner interests. The PVG offering could increase by up to 900,000 additional common units if the underwriters exercise a 30-day purchase option they are expected to be granted. If the offering is completed, most of the proceeds will be used by PVG to purchase newly issued Class B units from PVR and to make a capital contribution to PVR to maintain its two percent general partner interest. PVR expects to use the proceeds from the Class B units to repay debt.”

Oil and Gas Segment Review

See the Company’s October 25, 2006, news release for a more detailed discussion of third quarter 2006 drilling and production operations for the oil and gas segment.

Oil and gas operating income for the third quarter of 2006 was $18.1 million, compared to $27.0 million reported for the same quarter of 2005. Total oil and gas segment revenues decreased by two percent to $56.9 million from $57.8 million in the third quarter of 2005. A 15 percent increase in oil and natural gas production, from 6.9 billion cubic feet equivalent (Bcfe) in the third quarter of 2005 to a record 7.9 Bcfe in the third quarter of 2006, was more than offset by a decrease in realized prices. The average realized sales price for natural gas in the third quarter of 2006 was $6.89 per thousand cubic feet (Mcf), a decrease of 17 percent from $8.35 per Mcf realized in the third quarter of 2005. Because the Company accounted for its derivatives using hedge accounting in 2005, cash settlements on derivatives were included in the average realized sales price in the third quarter of 2005. Adjusted for cash received on derivative contracts settled during the third quarter of 2006, oil and gas segment revenues and the average realized sales price for natural gas would have increased by $2.6 million and $0.34 per Mcf to $59.5 million and $7.23 per Mcf.

Total oil and gas segment expenses increased 26 percent to $38.8 million in the third quarter of 2006 compared to $30.8 million in the third quarter of 2005, primarily due to the following:

• Operating expenses increased to $7.9 million in the third quarter of 2006 from $4.6 million in the third quarter of 2005. The increase was primarily due to additional leased compression at fields with increased production, downhole maintenance charges associated with horizontal CBM wells in Appalachia and Selma Chalk wells in Mississippi, increased surface repair costs and increased gathering fees related to HCBM and Cotton Valley wells.

• Exploration expense increased to $12.7 million in the third quarter of 2006 from $6.0 million in the third quarter of 2005. The increase was primarily due to an increase in dry hole costs related to the write off of six unsuccessful exploratory wells, the amortization of unproved property pools in 2006 and an increase in seismic costs due to the timing of seismic data purchases. These increases were partially offset by a decrease in delay rentals.

• Taxes other than income decreased to $1.8 million in the third quarter of 2006 from $3.4 million in the third quarter of 2005 due to a severance tax refund related to production in the Cotton Valley play and property tax adjustments in West Virginia.

• General and administrative expenses increased to $3.2 million in the third quarter of 2006 from $2.0 million in the third quarter of 2005, primarily due to increased payroll costs and consulting fees related to the Crow Creek acquisition.

• There were no impairment charges in the third quarter of 2006. In the third quarter of 2005, the Company recorded a $3.5 million impairment charge related to a change in estimate of the reserve base of a field in southeast Texas.

• Depreciation, depletion and amortization (DD&A) expense increased to $13.4 million in the third quarter of 2006 from $11.4 million in the third quarter of 2005. The increase was primarily the result of the 15 percent quarter-to-quarter production increase. The DD&A rate slightly increased to $1.69 per Mcfe produced in the third quarter of 2006 from $1.66 per Mcfe produced in the third quarter of 2005 as a result of a greater percentage of production coming from relatively higher cost horizontal CBM and Cotton Valley wells and general price inflation for equipment, services and tubulars used for drilling and development.

Coal Segment Review (Penn Virginia Resource Partners, L.P. – NYSE:PVR)

Third quarter 2006 operating income in the coal segment was $18.7 million, or 13 percent higher than the $16.6 million reported in the third quarter of 2005. Revenues increased to a record $29.9 million in the third quarter of 2006, a 15 percent increase over the $25.9 million reported in the third quarter of 2005. These increases were mainly a result of higher coal royalty revenues, which increased to $26.6 million in the third quarter of 2006, a 17 percent increase over $22.7 million in the third quarter of 2005. The coal royalty revenue increase was a result of higher coal prices, which caused the average royalty per ton to increase 13 percent to $3.03 in the third quarter of 2006 from $2.67 in the third quarter of 2005, and increased coal production to 8.8 million tons in the third quarter of 2006 from 8.5 million tons in the third quarter of 2005, primarily due to second quarter 2006 property acquisitions in central Appalachia.

Expenses increased to $11.1 million in the third quarter of 2006 from $9.3 million in the third quarter of 2005, due primarily to increased royalty expense related to increased production on subleased properties and depreciation, depletion and amortization (“DD&A”) resulting from higher coal production and a higher depletion rate on recently acquired reserves.

Natural Gas Midstream Segment Review (Penn Virginia Resource Partners, L.P. – NYSE: PVR)

Third quarter 2006 operating income in the natural gas midstream segment was a record $11.1 million compared to $5.9 million in the third quarter of 2005. Inlet volumes at the midstream segment’s gas processing plants and gathering systems were a record 14.6 billion cubic feet (Bcf) or approximately 159 million cubic feet per day (MMcfpd) for the third quarter of 2006, a 26 percent increase from 126 MMcfpd for the third quarter of 2005.

The gross processing margin for the third quarter of 2006, consisting of midstream revenues minus the cost of gas purchased, was a record $20.5 million, an increase of 45 percent over $14.1 million for the third quarter of 2005. This margin increased because average natural gas prices, the main component of the cost of gas purchased, decreased relatively more than the decrease in NGL prices, a main component of midstream revenues. Expenses other than cost of gas purchased increased to $10.2 million for the third quarter of 2006 compared to $8.8 million for the third quarter of 2005, due primarily to increased general and administrative expense and DD&A. Adjusted for cash payments on derivative contracts settled during the quarter, the gross processing margin was $14.0 million, an increase of seven percent over $13.1 million for the third quarter of 2005.

Capital Resources and Impact of Derivatives

As of September 30, 2006, the Company had borrowed $180.0 million under its revolving credit facility. PVR’s outstanding borrowings as of September 30, 2006, were $326.6 million, including $10.8 million of senior unsecured notes classified as current portion of long-term debt. Primarily due to increased PVR and PVA borrowings and higher interest rates, interest expense increased from $4.2 in the third quarter of 2005 to $7.1 million in the third quarter of 2006.

The Company uses commodity price derivative positions to manage price risk in its oil and gas and natural gas midstream segments, as summarized later in this release. In the oil and gas segment, the Company has hedged approximately 40 percent of its current natural gas production for the fourth quarter of 2006, dropping to approximately 20 percent and six percent for 2007 and 2008. For the fourth quarter of 2006 and full year 2007 and 2008, through PVR the natural gas midstream segment has hedged approximately 65, 30, and 30 percent of its commodity price exposure, based on its share of current plant production.

Beginning May 1, 2006, the Company elected to discontinue hedge accounting prospectively. From that date forward, the Company recognizes mark-to-market gains and losses in earnings currently, rather than deferring such amounts on its balance sheet. This change has no impact on the Company’s reported cash flows, but results of operations are affected by the volatility of mark-to-market gains and losses, which fluctuate with changes in oil and natural gas prices. Net income for the third quarter of 2006 included a mark-to-market derivative gain of $11.5 million on oil and gas segment derivatives and a $6.4 million gain on natural gas midstream segment derivatives. Net income for the first nine months of 2006 included a mark-to-market derivative gain of $22.5 million on oil and gas segment derivatives and an $11.7 million loss on natural gas midstream segment derivatives. Net income for the first nine months of 2006 also included a $0.6 million gain on ineffectiveness related to the oil and gas segment. Cash paid or received for derivative settlements in the third quarter of 2006 included $3.1 million in cash receipts related to the oil and gas segment and $7.3 million in cash payments related to the natural gas midstream segment. Cash paid or received for derivative settlements the first nine months of 2006 included $5.0 million in cash receipts related to the oil and gas segment and $15.4 million in cash payments related to the natural gas midstream segment.

Guidance for 2006

See the Guidance Table included in this release for guidance estimates for 2006. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as the Company’s operating environment changes.

Conference Call

A conference call and webcast, at which management will discuss third quarter 2006 results and the outlook for the remainder of 2006, is scheduled for Thursday, November 2, 2006, at 3:00 p.m. ET. Prepared remarks by A. James Dearlove, President and Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-877-407-9205 five to ten minutes before the scheduled start of the conference call, or via Internet webcast by logging on to the Company’s website at www.pennvirginia.com at least 20 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephone replay of the call will be available until November 3, 2006, at 11:59 p.m. ET by dialing 1-877-660-6853 and using replay passcodes: account number 286 and conference number 216950. An on-demand replay of the call will also be available at the Company’s website beginning shortly after the call.

******

A registration statement relating to the PVG common units has been filed with the Securities and Exchange Commission but has not yet become effective. The PVG common units may not be sold nor may offers to buy be accepted prior to the time the registration statement becomes effective. This communication does not constitute an offer to sell or the solicitation of an offer to buy nor shall there be any sale of the PVG common units in any state in which such offer, solicitation or sale would be unlawful prior to registration or qualification under the securities laws of any jurisdiction.

Penn Virginia Corporation (NYSE: PVA) is an energy company engaged in the exploration, acquisition, development and production of crude oil and natural gas. PVA is also the general partner and the largest unit holder in Penn Virginia Resource Partners, L.P. (NYSE: PVR), which manages coal properties and related assets and operates a midstream natural gas gathering and processing business. PVA is headquartered in Radnor, PA. For more information about PVA, visit the Company’s website at www.pennvirginia.com.

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following: the cost of finding and successfully developing oil and gas reserves; PVA’s ability to acquire new oil and gas reserves and the price for which such reserves can be acquired; energy prices generally and specifically, the price of crude oil, natural gas, NGLs and coal; the relationship between natural gas and NGL prices; the price of coal and its comparison to the price of natural gas and oil; the volatility of commodity prices for crude oil, natural gas, NGLs and coal; the projected demand for crude oil, natural gas, NGLs and coal; the projected supply of crude oil, natural gas, NGLs and coal; PVA’s ability to obtain adequate pipeline transportation capacity for its oil and gas production; non-performance by third party operators in wells in which PVA owns an interest; competition among producers in the oil and natural gas and coal industries generally and among natural gas midstream companies; the extent to which the amount and quality of actual production of PVA’s oil and natural gas or PVR’s coal differs from estimated recoverable proved oil and gas reserves and coal reserves; PVR’s ability to generate sufficient cash from its midstream and coal businesses to pay the minimum quarterly distribution to its general partner and its unitholders; hazards or operating risks incidental to PVA’s business and to PVR’s coal or midstream business; PVR’s ability to successfully manage its relatively new natural gas midstream business; PVR’s ability to acquire new coal reserves or

midstream assets on satisfactory terms; the price for which coal reserves can be acquired; PVR’s ability to continually find and contract for new sources of natural gas supply for its midstream business; PVR’s ability to retain existing or acquire new midstream customers; PVR’s ability to lease new and existing coal reserves; the ability of PVR’s lessees to produce sufficient quantities of coal on an economic basis from PVR’s reserves; the ability of PVR’s lessees to obtain favorable contracts for coal produced from its reserves; PVR’s exposure to the credit risk of its coal lessees and midstream customers; hazards or operating risks incidental to midstream operations; unanticipated geological problems; the dependence of PVR’s midstream business on having connections to third party pipelines; the availability of required drilling rigs, materials and equipment; the occurrence of unusual weather or operating conditions including force majeure events; the failure of equipment or processes to operate in accordance with specifications or expectations; the failure of PVR’s infrastructure and its lessees’ mining equipment or processes to operate in accordance with specifications or expectations; delays in anticipated start-up dates of PVA’s oil and natural gas production and PVR’s lessees’ mining operations and related coal infrastructure projects; environmental risks affecting the drilling and producing of oil and gas wells, the mining of coal reserves or the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by PVA and by PVR or PVR’s lessees; the risks associated with having or not having price risk management programs; labor relations and costs; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of current and future litigation regarding mine permitting; risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions (including the impact of potential terrorist attacks); the experience and financial condition of PVR’s coal lessees and midstream customers, including the lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others; PVR’s ability to expand its midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner; coal handling joint venture operations; changes in financial market conditions; and the completion of PVG’s initial public offering.

Additional information concerning these and other factors can be found in PVA’s press releases and public periodic filings with the Securities and Exchange Commission, including PVA’s Annual Report on Form 10-K for the year ended December 31, 2005. Many of the factors that will determine PVA’s 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. PVA undertakes no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

PENN VIRGINIA CORPORATION

OPERATIONS SUMMARY

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Production
Natural gas (MMcf)		7,332			6,473			21,009			18,826
Oil and condensate (MBbl)		97			69			283			230
Total oil, condensate and natural gas production (MMcfe)		7,914			6,887			22,707			20,206
Coal royalty tons (thousands)		8,782			8,531			24,467			22,496
Inlet volumes (MMcf)		14,643			11,567			39,431			26,963
Prices and margin
Natural gas ($/Mcf)	$	6.89		$	8.35		$	7.63		$	7.28
Oil and condensate ($/Bbl)	$	61.48		$	48.83		$	57.87		$	44.03
Coal royalties ($/ton)	$	3.03		$	2.67		$	3.00		$	2.71
Gross midstream processing margin (in thousands)	$	20,537		$	14,128		$	50,725		$	31,073
CONSOLIDATED STATEMENTS OF EARNINGS - unaudited
(in thousands, except per share data)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Revenues
Natural gas	$	50,540		$	54,071		$	160,384		$	137,011
Oil and condensate		5,964			3,369			16,378			10,128
Natural gas midstream		100,809			101,940			305,340			213,351
Coal royalties		26,612			22,739			73,288			60,921
Other		4,468			4,240			13,060			11,157
Total revenues		188,393			186,359			568,450			432,568
Expenses
Cost of midstream gas purchased		80,272			87,812			254,615			182,278
Operating		14,259			9,141			33,438			22,642
Exploration		12,660			5,960			26,061			31,550
Taxes other than income		2,322			4,080			11,217			11,481
General and administrative		10,900			8,369			33,289			23,876
Impairment of oil and gas properties		—			3,488			—			3,488
Depreciation, depletion and amortization		23,336			20,701			66,581			56,324
Total expenses		143,749			139,551			425,201			331,639
Operating income		44,644			46,808			143,249			100,929
Other income (expense)
Interest expense		(7,108	)		(4,195	)		(17,292	)		(11,070	)
Interest and other income		379			276			1,138			971
Derivatives		17,940			3,578			11,403			(11,186	)
Income from operations before minority interest and income taxes		55,855			46,467			138,498			79,644
Minority interest		18,539			13,684			31,187			22,274
Income tax expense		14,435			12,793			42,105			22,693
Net income	$	22,881		$	19,990		$	65,206		$	34,677
Per share data
Net income per share, basic	$	1.22		$	1.08		$	3.49		$	1.87
Net income per share, diluted	$	1.21		$	1.07		$	3.46		$	1.85
Weighted average shares outstanding, basic		18,679			18,560			18,658			18,524
Weighted average shares outstanding, diluted		18,895			18,760			18,872			18,707

PENN VIRGINIA CORPORATION

CONSOLIDATED BALANCE SHEETS

(in thousands)

	September 30, 2006		December 31, 2005
	(unaudited)
Assets
Current assets	$	164,177	$	178,185
Net property and equipment		1,283,889		983,219
Equity investments		25,069		26,672
Goodwill and intangibles, net		41,970		45,769
Other assets		19,222		17,701
Total assets	$	1,534,327	$	1,251,546
Liabilities and Shareholders’ Equity
Current liabilities	$	135,914	$	154,528
Long-term debt		180,000		79,000
Long-term debt of Penn Virginia Resource Partners, L.P.		315,772		246,846
Other liabilities and deferred taxes		210,467		147,340
Minority interest in Penn Virginia Resource Partners, L.P.		317,199		313,524
Shareholders’ equity		374,975		310,308
Total liabilities and shareholders’ equity	$	1,534,327	$	1,251,546

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Operating Activities
Net income	$	22,881		$	19,990		$	65,206		$	34,677
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		23,336			20,701			66,581			56,324
Commodity derivative contracts:
Total derivative losses		(17,675	)		273			(10,042	)		15,422
Cash settlements of derivatives		(4,216	)		(4,886	)		(10,433	)		(7,112	)
Impairment of oil and gas properties		—			3,488			—			3,488
Minority interest		18,539			13,684			31,187			22,274
Deferred income taxes		13,248			6,750			32,071			10,793
Dry hole and unproved leasehold expense		9,566			2,733			17,925			21,649
Other		919			4,575			5,483			6,464
Operating cash flow (see attached table “Reconciliation of Certain Non-GAAP Financial Measures”)		66,598			67,308			197,978			163,979
Changes in operating assets and liabilities		(19,437	)		(3,467	)		(917	)		(15,472	)
Net cash provided by operating activities		47,161			63,841			197,061			148,507
Investing Activities
Proceeds from sale of properties		30			6,624			2,505			17,375
Additions to property and equipment		(76,700	)		(51,938	)		(182,239	)		(129,898	)
Acquisitions, net of cash acquired		(6,816	)		(67,492	)		(171,479	)		(290,169	)
Net cash used in investing activities		(83,486	)		(112,806	)		(351,213	)		(402,692	)
Financing Activities
Dividends paid		(2,101	)		(2,087	)		(6,298	)		(6,250	)
Distributions paid to minority interest holders		(9,827	)		(8,491	)		(28,144	)		(22,247	)
Proceeds from issuance of PVR partners’ capital		—			39			—			126,475
Net proceeds from PVA borrowings		35,000			—			101,000			13,000
Net proceeds from PVR borrowings		10,000			54,200			71,500			140,200
Payments for debt issuance costs		—			(346	)		—			(2,385	)
Issuance of stock		1,833			1,370			2,567			1,927
Net cash provided by financing activities		34,905			44,685			140,625			250,720
Net increase (decrease) in cash and cash equivalents		(1,420	)		(4,280	)		(13,527	)		(3,465	)
Cash and cash equivalents-beginning balance		13,806			26,286			25,913			25,471
Cash and cash equivalents-ending balance	$	12,386		$	22,006		$	12,386		$	22,006

PENN VIRGINIA CORPORATION

QUARTER SEGMENT INFORMATION - unaudited

(Dollars in millions except where noted)

	Oil and Gas				Coal		Natural Gas Midstream		Other			Consolidated
	Amount		(per Mcfe) *
Three months ended September 30, 2006
Production
Oil, condensate and gas (MMcfe)		7,914
Natural gas (MMcf)		7,332
Crude oil and condensate (MBbl)		97
Coal royalty tons (thousands of tons)						8,782
Inlet volumes (MMcf)								14,643
Revenues
Natural gas	$	50,540	$	6.89	$	—	$	—	$	—		$	50,540
Oil and condensate		5,954		61.38		—		—		10			5,964
Natural gas midstream		—				—		100,809		—			100,809
Coal royalties		—				26,612		—		—			26,612
Other		402				3,278		795		(7	)		4,468
Total revenues		56,896		7.19		29,890		101,604		3			188,393
Expenses
Cost of midstream gas purchased		—		—		—		80,272		—			80,272
Operating		7,882		1.00		3,340		3,038		(1	)		14,259
Exploration		12,660		1.60		—		—		—			12,660
Taxes other than income		1,750		0.22		154		329		89			2,322
General and administrative		3,181		0.40		2,097		2,504		3,118			10,900
Depreciation, depletion and amortization		13,365		1.69		5,551		4,313		107			23,336
Total expenses		38,838		4.91		11,142		90,456		3,313			143,749
Operating income (loss)	$	18,058	$	2.28	$	18,748	$	11,148	$	(3,310	)	$	44,644
Additions to property and equipment and acquisitions, net of cash acquired	$	70,558			$	5,735	$	6,036	$	1,187		$	83,516
	Oil and Gas				Coal		Natural Gas Midstream		Other			Consolidated
	Amount		(per Mcfe) *
Three months ended September 30, 2005
Production
Oil, condensate and gas (MMcfe)		6,887
Natural gas (MMcf)		6,473
Crude oil and condensate (MBbl)		69
Coal royalty tons (thousands of tons)						8,531
Inlet volumes (MMcf)								11,567
Revenues
Natural gas	$	54,071	$	8.35	$	—	$	—	$	—		$	54,071
Oil and condensate		3,369		48.83		—		—		—			3,369
Natural gas midstream		—				—		101,940		—			101,940
Coal royalties		—				22,739		—		—			22,739
Other		405				3,184		543		108			4,240
Total revenues		57,845		8.40		25,923		102,483		108			186,359
Expenses
Cost of midstream gas purchased		—		—		—		87,812		—			87,812
Operating		4,553		0.66		1,931		2,657		—			9,141
Exploration		5,960		0.87		—		—		—			5,960
Taxes other than income		3,424		0.50		219		340		97			4,080
General and administrative		1,966		0.29		1,917		1,873		2,613			8,369
Impairment of oil and gas properties		3,488		0.51		—		—		—			3,488
Depreciation, depletion and amortization		11,433		1.66		5,257		3,902		109			20,701
Total expenses		30,824		4.48		9,324		96,584		2,819			139,551
Operating income (loss)	$	27,021	$	3.92	$	16,599	$	5,899	$	(2,711	)	$	46,808
Additions to property and equipment and acquisitions, net of cash acquired (1)	$	34,808			$	81,339	$	4,344	$	85		$	120,576

* Natural gas revenues are shown per Mcf, oil and gas condensate revenues are shown per Bbl, and all other amounts are shown per Mcfe.

(1) Coal segment includes noncash expenditures of $14.4 million.

PENN VIRGINIA CORPORATION

YEAR-TO-DATE SEGMENT INFORMATION - unaudited

(Dollars in millions except where noted)

	Oil and Gas				Coal		Natural Gas Midstream		Other			Consolidated
	Amount		(per Mcfe) *
Nine months ended September 30, 2006
Production
Oil, condensate and gas (MMcfe)		22,707
Natural gas (MMcf)		21,009
Crude oil and condensate (MBbl)		283
Coal royalty tons (thousands of tons)						24,467
Inlet volumes (MMcf)								39,431
Revenues
Natural gas	$	160,384	$	7.63	$	—	$	—	$	—		$	160,384
Oil and condensate		16,378		57.87		—		—		—			16,378
Natural gas midstream		—				—		305,340		—			305,340
Coal royalties		—				73,288		—		—			73,288
Other		1,521				9,827		1,666		46			13,060
Total revenues		178,283		7.85		83,115		307,006		46			568,450
Expenses
Cost of midstream gas purchased		—		—		—		254,615		—			254,615
Operating		19,490		0.86		5,561		8,387		—			33,438
Exploration		26,061		1.15		—		—		—			26,061
Taxes other than income		9,162		0.40		565		1,054		436			11,217
General and administrative		8,649		0.38		6,796		8,209		9,635			33,289
Depreciation, depletion and amortization		38,755		1.71		15,050		12,451		325			66,581
Total expenses		102,117		4.50		27,972		284,716		10,396			425,201
Operating Income	$	76,166	$	3.35	$	55,143	$	22,290	$	(10,350	)	$	143,249
Additions to property and equipment and acquisitions, net of cash acquired (2)	$	275,775			$	80,902	$	27,577	$	2,223		$	386,477
	Oil and Gas				Coal		Natural Gas Midstream (1)		Other			Consolidated
	Amount		(per Mcfe) *
Nine months ended September 30, 2005
Production
Oil, condensate and gas (MMcfe)		20,206
Natural gas (MMcf)		18,826
Crude oil and condensate (MBbl)		230
Coal royalty tons (thousands of tons)						22,496
Inlet volumes (MMcf)								26,963
Revenues
Natural gas	$	137,011	$	7.28	$	—	$	—	$	—		$	137,011
Oil and condensate		10,128		44.03		—		—		—			10,128
Natural gas midstream		—				—		213,351		—			213,351
Coal royalties		—				60,921		—		—			60,921
Other		581				8,507		1,424		645			11,157
Total revenues		147,720		7.31		69,428		214,775		645			432,568
Expenses
Cost of midstream gas purchased		—		—		—		182,278		—			182,278
Operating		11,629		0.58		4,104		6,626		283			22,642
Exploration		31,550		1.56		—		—		—			31,550
Taxes other than income		9,484		0.47		727		930		340			11,481
General and administrative		6,249		0.31		5,962		4,107		7,558			23,876
Impairment of oil and gas properties		3,488		0.17		—		—		—			3,488
Depreciation, depletion and amortization		33,777		1.67		13,440		8,797		310			56,324
Total expenses		96,177		4.76		24,233		202,738		8,491			331,639
Operating Income	$	51,543	$	2.55	$	45,195	$	12,037	$	(7,846	)	$	100,929
Additions to property and equipment and acquisitions, net of cash acquired (3)	$	120,133			$	110,370	$	203,810	$	150		$	434,463

* Natural gas revenues are shown per Mcf, oil and gas condensate revenues are shown per Bbl, and all other amounts are shown per Mcfe.

(1) Natural Gas Midstream segment acquired in March 2005.

(2) Oil and gas segment includes noncash expenditures of $32.8 million.

(3) Oil and gas segment includes noncash expenditures of $13.2 million. Coal segment includes noncash expenditures of $14.4 million.

PENN VIRGINIA CORPORATION

RECONCILIATION OF CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2006			2005			2006			2005
Reconciliation of GAAP “Net cash provided by operating activities” to Non-GAAP “Operating cash flow”
Net cash provided by operating activities	$	47,161		$	63,841		$	197,061		$	148,507
Adjustments:
Changes in operating assets and liabilities		19,437			3,467			917			15,472
Operating cash flow (see Note 1 below)	$	66,598		$	67,308		$	197,978		$	163,979
Reconciliation of GAAP “Additions to property and equipment” to Non-GAAP “Capital expenditures”
Additions to property and equipment	$	76,700		$	51,938		$	182,239		$	129,898
Acquisitions, net of cash acquired		6,816			67,492			171,479			290,169
Seismic expenditures		1,307			797			4,947			6,876
Delay rentals and other expenditures		1,650			2,226			3,056			2,817
Acquisitions of non-PPE assets and liabilities		488			—			(2,356	)		—
Sale of lease rights		—			(6,625	)		—			(6,625	)
Change in accrued capital expenditures		(3,300	)		1,619			(844	)		739
Less: Capitalized interest		(882	)		(1,118	)		(1,788	)		(2,425	)
Capital expenditures (see Note 2 below)	$	82,779		$	116,329		$	356,733		$	421,449

Note 1 - Operating cash flow represents net cash provided by operating activities before changes in assets and liabilities. Operating cash flow is presented because management believes it is a useful adjunct to net cash provided by operating activities under accounting principles generally accepted in the United States (GAAP). Management believes that operating cash flow is widely accepted as a financial indicator of an oil and gas company’s ability to generate cash which is used to internally fund exploration and development activities, service debt and pay dividends. This measure is widely used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Operating cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing, or financing activities as an indicator of cash flows, or as a measure of liquidity, or as an alternative to net income.

Note 2 - Capital expenditures represents cash additions to property and equipment, plus cash paid for acquisitions, plus seismic expenditures, delay rentals and other expenditures, change in accrued capital expenditures and non-cash well accruals, minus capitalized interest. Management believes capital expenditures provide useful information regarding the Company’s capital program as a supplement to cash additions to property and equipment

PENN VIRGINIA CORPORATION

GUIDANCE TABLE

(Dollars in millions except where noted)

Penn Virginia Corporation is providing the following guidance regarding financial and operational expectations for 2006.

	Actual									2006 Guidance
	First Quarter 2006			Second Quarter 2006		Third Quarter 2006		YTD 2006
Oil & Gas Segment:
Production:
Natural gas (Bcf) - See Note a		6.8		6.9		7.3		21.0		28.5		-		29.9
Crude oil and condensate (MBbl) - See Note b		91		95		97		283		325		-		350
Equivalent production (Bcfe)		7.3		7.6		7.9		22.7		30.5		-		32.0
Equivalent daily production (MMcfe)		81.1		83.2		86.0		83.2		83.6		-		87.7
Expenses:
Direct expenses	$	11.5		13.0		12.8		37.3		49.0		-		51.0
Exploration	$	7.9		5.5		12.7		26.1		36.0		-		38.0
Depreciation, depletion and amortization ($ per Mcfe)	$	1.73		1.70		1.69		1.71		1.70		-		1.80
Capital Expenditures:
Development drilling	$	28.2		37.8		50.1		116.1		150.0		-		155.0
Exploratory drilling	$	9.9		8.8		5.0		23.7		47.0		-		50.0
Pipeline, gathering, facilities	$	2.8		4.3		4.8		11.9		17.0		-		18.0
Seismic	$	2.4		1.2		1.3		4.9		6.5		-		7.0
Lease acquisition, field projects and other - See Note c	$	3.9		9.4		3.7		17.0		28.0		-		30.0
Proved property acquisitions	$	—		72.5		—		72.5		71.5		-		72.0
Total Oil & Gas Capital Expenditures	$	47.2		134.0		64.9		246.1		320.0		-		332.0
Coal Segment (PVR):
Coal royalty tons (millions)		7.7		8.0		8.8		24.5		32.5		-		34.0
Revenues:
Average royalty per ton	$	2.90		3.04		3.03		3.00		2.95		-		3.00
Other	$	2.9		3.6		3.3		9.8		13.2		-		14.0
Expenses:
Direct expenses	$	3.5		3.9		5.6		12.9		17.0		-		18.0
Depreciation, depletion and amortization	$	4.7		4.7		5.6		15.1		20.0		-		21.0
Capital Expenditures:
Expansion and acquisitions	$	4.8		69.2		6.4		80.4		84.0		-		84.6
Maintenance capital expenditures	$	0.1		—		—		0.1		0.3		-		0.4
Total Coal Capital Expenditures	$	4.9		69.2		6.4		80.5		84.3		-		85.0
Natural Gas Midstream Segment (PVR):
Inlet volumes (MMcf per day) - see Note d		134		140		159		144		145		-		150
Expenses:
Direct expenses	$	5.9		5.8		5.9		17.7		23.5		-		24.0
Depreciation, depletion and amortization	$	4.1		4.1		4.3		12.5		16.5		-		17.0
Capital Expenditures:
Expansion and acquisitions	$	0.6		17.4		2.5		20.5		23.0		-		24.0
Maintenance capital expenditures	$	2.0		2.3		3.0		7.3		9.5		-		10.0
Total Midstream Capital Expenditures	$	2.6		19.7		5.5		27.8		32.5		-		34.0
Corporate and Other:
General and administrative expense	$	2.9		3.5		3.1		9.6		13.0		-		14.0
Interest expense:
PVA average long-term debt outstanding	$	73.5		91.5		149.0		104.4		140.0		-		160.0
PVA interest rate		5.3	%	5.4	%	7.0	%	6.3	%	6.5	%	-		7.0	%
Percentage capitalized - see Note e		37	%	32	%	33	%	34	%	35	%	-		40	%
PVR average long-term debt outstanding	$	254.2		284.1		326.6		289.1		325.0		-		330.0
PVR interest rate assumed		5.9	%	6.0	%	6.6	%	6.2	%	6.3	%	-		6.6	%
Minority interest in PVR - see Note f	$	4.9		7.8		18.5		31.2		see Note e
Income tax rate - see Note g		39	%	41	%	39	%	39	%			40	%
Other capital expenditures	$	0.3		0.7		1.2		2.2		5.0		-		6.0

These estimates are meant to provide guidance only and are subject to change as the operating environment of the Company changes.

See Notes on following page.

PENN VIRGINIA CORPORATION

GUIDANCE TABLE

(Dollars in millions except where noted)

Notes to Guidance Table:

a - The oil and gas segment’s natural gas derivative positions as of September 30, 2006, are summarized below:

	Average MMBtu Per Day	Additional Put		Weighted Average Price per MMBtu Collars
				Floor		Ceiling
Fourth Quarter 2006
Costless collar	26,269			$	8.17	$	15.15
Three-way collar (October only)	25,000	$	4.50	$	6.00	$	9.40
Stand-alone put	1,333			$	9.00
First Quarter 2007
Costless collar	20,000			$	9.00	$	19.03
Three-way collar	3,000	$	5.00	$	8.00	$	11.25
Second Quarter 2007
Costless collar	15,000			$	7.33	$	12.93
Three-way collar	3,000	$	5.00	$	8.00	$	11.25
Third Quarter 2007
Costless collar	15,000			$	7.33	$	12.93
Three-way collar	3,000	$	5.00	$	8.00	$	11.25
Fourth Quarter 2007
Costless collar	11,667			$	8.28	$	15.78
Three-way collar	3,000	$	5.00	$	8.00	$	11.25
First Quarter 2008
Costless collar	10,000			$	9.00	$	17.95
Three-way collar	2,500	$	5.00	$	8.00	$	10.75
Second Quarter 2008
Three-way collar	2,500	$	5.00	$	8.00	$	10.75
Third Quarter 2008
Three-way collar	2,500	$	5.00	$	8.00	$	10.75
Fourth Quarter 2008
Three-way collar	2,500	$	5.00	$	8.00	$	10.75

The costless collar natural gas prices per MMBtu per quarter include the effects of basis differentials, if any.

b - The oil and gas segment’s oil derivative positions as of September 30, 2006, are summarized below:

	Average Bbbls Per Day	Weighted Average Price per Bbl Collars
		Floor		Ceiling
Fourth Quarter 2006 through Fourth Quarter 2007	200	$	60.00	$	72.20

c - Lease acquisition excludes total non-cash expenditures of $32.8 million in the nine months ended September 30, 2006, related to

     deferred taxes in the Crow Creek Acquisition.

d - The natural gas midstream segment’s derivative positions as of September 30, 2006, are summarized below:

	Average Volume Per Day		Weighted Average Price
Ethane Swaps (revenue)	(in gallons	)		(per gallon	)
Fourth Quarter 2006	73,126		$	0.4870
First Quarter 2007 through Fourth Quarter 2007	34,440		$	0.5050
First Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700
Propane Swaps (revenue)	(in gallons	)		(per gallon	)
Fourth Quarter 2006	52,080		$	0.7060
First Quarter 2007 through Fourth Quarter 2007	26,040		$	0.7550
First Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175
Crude Oil Swaps (revenue)	(in barrels	)		(per barrel	)
Fourth Quarter 2006	1,100		$	44.45
First Quarter 2007 through Fourth Quarter 2007	560		$	50.80
First Quarter 2008 through Fourth Quarter 2008	560		$	49.27
Crude Oil Collars (revenue)	(in barrels	)		(per barrel	)
Fourth Quarter 2006 (October only)	270		$	73.59
Natural Gas Swaps (cost of gas purchased)	(in MMBtu	)		(per MMBtu	)
Fourth Quarter 2006	8,005		$	6.98
First Quarter 2007 through Fourth Quarter 2007	4,000		$	6.97
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97

e - The Company capitalizes a portion of interest expense incurred to recognize the carrying cost of certain unproved properties as

      required by accounting principles generally accepted in the United States.

f - Penn Virginia owns 39 percent of Penn Virginia Resource Partners, L.P. (PVR). Minority interest reflects the remaining 61 percent

     owned by parties other than Penn Virginia, less the general partner’s incentive distribution rights.

g - Deferred federal and state income taxes are expected to comprise approximately 60% to 70% of the Company’s income tax

     expense for the full year.