Penn Virginia Resource Partners, L.P.

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

FOR IMMEDIATE RELEASE

Contact:	James W. Dean
	Vice President, Investor Relations
	Ph: (610) 687-8900 Fax: (610) 687-3688
	E-Mail: invest@pennvirginia.com

PENN VIRGINIA RESOURCE PARTNERS, L.P.

ANNOUNCES THIRD QUARTER 2009 RESULTS

RADNOR, PA (BusinessWire) November 4, 2009 – Penn Virginia Resource Partners, L.P. (NYSE: PVR) today reported financial and operational results for the three months ended September 30, 2009 and provided an update of full-year 2009 guidance.

Third Quarter 2009 Highlights

Third quarter 2009 highlights and results, with comparisons to third quarter 2008 results, included the following:

Distributable cash flow (DCF), a non-GAAP (generally accepted accounting principles) measure, of $37.2 million, as compared to $28.0 million in the prior year quarter;

Adjusted net income, a non-GAAP measure which excludes the effects of the non-cash change in derivatives fair value, of $22.2 million, or $0.30 per limited partner unit, as compared to $16.3 million, or $0.19 per limited partner unit, in the prior year quarter;

Net income of $18.8 million, or $0.24 per limited partner unit, as compared to $44.6 million, or $0.73 per limited partner unit;

Coal production by lessees of 8.4 million tons, as compared to 8.5 million tons;

Coal royalties revenue, net of coal royalties expense, of $28.2 million, or $3.37 per ton, as compared to $31.2 million, or $3.67 per ton;

Quarterly natural gas midstream system throughput volumes of 29.8 billion cubic feet (Bcf), or 324 million cubic feet (MMcf) per day, as compared to 27.7 Bcf, or 302 MMcf per day;

Midstream gross margin, prior to the cash impact of derivatives, of $26.1 million, or $0.88 per thousand cubic feet (Mcf), as compared to $30.0 million, or $1.08 per Mcf; and

Midstream gross margin, adjusted for the cash impact of midstream derivatives, of $28.1 million, or $0.94 per Mcf, as compared to $17.5 million, or $0.63 per Mcf.

Reconciliations of non-GAAP financial measures to GAAP-based measures appear in the financial tables later in this release.

DCF for the third quarter of 2009 of $37.2 million was approximately $9.3 million, or 33 percent higher, than $28.0 million of DCF in the third quarter of 2008 primarily due to:

a $9.2 million increase in operating income (adjusted for the cash impact of midstream derivatives and before depreciation, depletion and amortization (DD&A) expense) from the natural gas midstream segment (PVR Midstream), due to an increase in cash receipts from settlements of commodity derivatives;

a $5.0 million decrease in interest and other expenses primarily related to a $3.8 million "make-whole" payment related to the early repayment of senior unsecured notes in the prior year quarter, as well as lower interest expense; and

a $2.4 million decrease in other capital expenditures.

These increases in DCF were partially offset by a $5.9 million decrease in operating income (before DD&A expense) from the coal and natural resource management segment (PVR Coal & Natural Resource Management) primarily due to decreases in coal royalties, oil and gas royalties, and other revenue, offset in part by decreased operating expenses, and a $1.5 million increase in cash paid to settle interest rate derivatives. DCF in the third quarter of 2009 was $2.6 million, or seven percent, higher than the $34.6 million of DCF in the second quarter of 2009 primarily due to improved midstream segment gross margin.

The $5.9 million, or 36 percent, increase in adjusted net income as compared to the prior year quarter was primarily due to a $7.4 million increase in operating income from PVR Midstream, adjusted for the cash impact of midstream derivatives, and the $5.0 million decrease in interest and other expenses. These increases were offset in part by a $5.1 million decrease in operating income from PVR Coal & Natural Resource Management and the $1.5 million increase in cash paid to settle interest rate derivatives.

The $25.7 million, or 58 percent, decrease in net income as compared to the prior year quarter was due to an $18.5 million change in derivatives expense resulting from changes in the valuation of unrealized derivative positions and a $12.2 million decrease in operating income, partially offset by the $5.0 million decrease in interest and other expenses.

Cash Distribution

As previously announced, on November 13, 2009, we will pay to unitholders of record as of November 6, 2009 a quarterly cash distribution of $0.47 per unit, or an annualized rate of $1.88 per unit, covering the period of July 1 through September 30, 2009. The distribution remains unchanged from the distribution paid with respect to each of the previous four quarters.

Management Comment

A. James Dearlove, Chief Executive Officer of PVR, said, “We are pleased to report that distributable cash flow generated by our two business segments increased by $2.6 million, or seven percent, over the second quarter of 2009 and was $9.3 million, or 33 percent, higher than the third quarter of 2008.

“The significant improvement in sequential quarterly results was largely due to PVR Midstream, as fractionation, or frac, spreads improved over the second quarter of 2009 due to higher natural gas liquids (NGLs) prices. We also began to see the benefits of the acquisition of a processing plant and expanded capacity in our Panhandle system, which allows us to process gas volumes of approximately 50 MMcf per day which were previously being bypassed and processed by third parties as a result of processing capacity constraints. We anticipate results from the midstream segment will continue to improve as producers‘ drilling activity is expected to increase in late 2009 and into 2010 due to the nascent recovery in spot and futures prices for natural gas.

“Coal royalties revenue, net of coal royalties expense, which accounted for approximately 84 percent of the Coal and Natural Resource Management segment’s third quarter revenues, was sequentially flat as compared to the second quarter of 2009, but was nine percent lower than the strong prior year quarter. Other revenues, which accounted for the remaining 16 percent of the segment’s second quarter revenues, were adversely impacted by decreases in the prices of timber and natural gas. We continue to benefit from the long-term contract prices our lessees previously negotiated with their customers.

“As of September 30, 2009, we had approximately $170 million of unused borrowing capacity under our revolving credit facility, which we believe provides adequate capital to support modest growth opportunities. We continue to review growth projects for both segments and we remain confident in the long-term fundamental characteristics of our business.”

Coal and Natural Resource Management Segment Review

During the third quarter of 2009, operating income for PVR Coal & Natural Resource Management decreased by 19 percent to $21.2 million from $26.3 million in the prior year quarter. Total revenues, net of coal royalties expense, decreased by $5.9 million, or 15 percent, to $33.6 million from $39.5 million in the prior year quarter due to a $2.9 million, or nine percent, decrease in coal royalties revenue, net of coal royalties expense, a $1.4 million decrease in oil and gas royalties revenue resulting from lower commodity prices and a $1.6 million decrease in timber and other revenues. As compared to the second quarter of 2009, operating income was four percent higher. Total revenues, net of coal royalties expense, of $33.6 million was flat as compared to the second quarter of 2009.

Coal royalties revenue, net of coal royalties expense, was nine percent lower than the prior year quarter, primarily due to a $0.30, or eight percent decrease, in average net coal royalties per ton to $3.37 in the third quarter of 2009 as compared to $3.67 in the prior year quarter. Quarter to quarter lessee production was relatively unchanged, with decreases in Northern and Central Appalachia offset by production increases in the San Juan and Illinois Basins. Operating expenses, excluding coal royalties expense, decreased by seven percent to $12.4 million primarily due to lower DD&A and other operating expenses.

Natural Gas Midstream Segment Review

During the third quarter, operating income for PVR Midstream decreased 52 percent to $6.6 million from $13.7 million in the prior year quarter. Adjusted for the cash impact of derivatives, operating income increased 629 percent to $8.6 million from $1.2 million in the prior year quarter. Midstream gross margin decreased by 13 percent to $26.1 million, or $0.88 per Mcf, from $30.0 million, or $1.08 per Mcf, in the prior year quarter primarily due to a decrease in the price of NGLs as a result of reduced demand, partially offset by a seven percent increase in system throughput volumes and increased processed volumes. Adjusted for the cash impact of derivatives, midstream gross margin was $28.1 million, or $0.94 per Mcf, up 61 percent from $17.5 million, or $0.63 per Mcf, in the prior year quarter and up 16 percent from $24.3 million, or $0.77 per Mcf, in the second quarter of 2009.

System throughput volumes at our gas processing plants and gathering systems increased seven percent to 29.8 Bcf, or approximately 324 MMcf per day, in the third quarter of 2009 from 27.7 Bcf, or approximately 302 MMcf per day, in the prior year quarter. The volumes increased primarily as a result of contributions from expansions and acquisitions completed in 2008 and 2009, as well as successful results by producers connected to our gathering systems. While system throughput volumes in the third quarter were 20 MMcf per day, or six percent, lower than the 344 MMcf per day in the second quarter of 2009, processed volumes increased due to the acquisition of a processing plant and expanded capacity in our Panhandle system, which allows us to process gas volumes of approximately 50 MMcf per day that were previously being bypassed and processed by third parties due to processing capacity constraints. Other expenses increased by $2.9 million, or 15 percent, to $21.5 million, primarily due to higher DD&A, operating and G&A expenses resulting from acquisitions and increased system throughput volumes.

Capital Resources and Impact of Derivatives

As of September 30, 2009, we had outstanding borrowings of $628.1 million under our $800 million revolving credit facility and $11.3 million of cash and equivalents, with remaining revolver borrowing capacity of approximately $170 million. The $60.0 million increase in outstanding borrowings as compared to the $568.1 million outstanding as of December 31, 2008 was primarily due to capital expenditures during the first nine months of 2009. Interest expense decreased from $7.1 million in the third quarter of 2008 to $6.5 million in the third quarter of 2009 due to decreased interest rates, offset in part by the higher level of outstanding borrowings during the quarter as compared to the prior year quarter.

For the third quarter of 2009, derivatives expense was $2.8 million, as compared to derivatives income of $15.7 million in the prior year quarter. Cash settlements of derivatives resulted in net cash payments of $0.3 million during the third quarter of 2009 related to commodity and interest rate derivatives, as compared to $14.1 million of net cash payments in the prior year quarter, a $13.8 million improvement. See the Natural Gas Midstream Segment Review in this release for a discussion of the impact of derivatives on PVR Midstream’s gross margin. See the Guidance Table included in this release for details of derivative positions as of September 30, 2009.

Guidance for 2009

See the Guidance Table included in this release for guidance estimates for full-year 2009. These estimates, including capital expenditure plans, are meant to provide guidance only and are subject to revision as our operating environment changes.

Conference Call

A joint conference call and webcast, during which management will discuss third quarter 2009 financial and operational results for PVR and PVG, is scheduled for Thursday, November 5, 2009 at 1:00 p.m. ET. Prepared remarks by A. James Dearlove, Chief Executive Officer, will be followed by a question and answer period. Investors and analysts may participate via phone by dialing 1-866-630-9986 five to ten minutes before the scheduled start of the conference call and using the passcode 3241667, or via webcast by logging on to our website at www.pvresource.com at least 20 minutes prior to the scheduled start of the call to download and install any necessary audio software. A telephonic replay will be available approximately two hours after the call for two weeks by dialing toll free 888-203-1112 (international: 719-457-0820) and using the replay code 3241667. In addition, an on-demand replay of the webcast will also be available for two weeks at PVR’s or PVG’s websites beginning 24 hours after the webcast.

******

Headquartered in Radnor, PA, Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a publicly traded limited partnership formed by Penn Virginia Corporation (NYSE: PVA). PVR manages coal and natural resource properties and related assets and operates a midstream natural gas gathering and processing business.

For more information about us, visit our website at www.pvresource.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 volatility of commodity prices for natural gas, NGLs and coal; our ability to access external sources of capital; any impairment writedowns of our assets; the relationship between natural gas, NGL and coal prices; the projected demand for and supply of natural gas, NGLs and coal; competition among producers in the coal industry generally and among natural gas midstream companies; the extent to which the amount and quality of actual production of our coal differs from estimated recoverable coal reserves; our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders; the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream businesses; our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms;our ability to retain existing or acquire new natural gas midstream customers and coal lessees; the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production; the occurrence of unusual weather or operating conditions including force majeure events; delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business; environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by us or our lessees; hedging results; 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, interest rates and financial and credit markets) and political conditions (including the impact of potential terrorist attacks); and other risks set forth in our Annual Report on Form 10-K for the fiscal year ended December 31, 2008.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2008. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF EARNINGS - unaudited

(dollars in thousands, except per unit data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Revenues
Natural gas midstream	$	118,443		$	241,282		$	348,882		$	601,127
Coal royalties		29,821			33,308			90,448			88,911
Coal services		1,869			1,815			5,502			5,518
Other		5,492			8,871			16,971			23,039
Total revenues		155,625			285,276			461,803			718,595

Expenses
Cost of midstream gas purchased		92,355			211,262			285,129			513,778
Coal royalties expense		1,587			2,125			4,380			8,034
Operating		7,443			6,916			22,558			16,519
Taxes other than income		1,005			969			3,208			3,017
General and administrative		7,568			7,078			23,421			20,339
Depreciation, depletion and amortization		17,851			16,903			51,971			41,322
Total expenses		127,809			245,253			390,667			603,009

Operating income		27,816			40,023			71,136			115,586

Other income (expense)
Interest expense		(6,505	)		(7,060	)		(18,486	)		(17,366	)
Interest income and other		323			(4,153	)		969			(3,233	)
Derivatives		(2,810	)		15,742			(12,005	)		(6,424	)

Net income	$	18,824		$	44,552		$	41,614		$	88,563

Allocation of net income:
General partner's interest in net income	$	6,291		$	6,806		$	18,576		$	17,482
Limited partners' interest in net income	$	12,533		$	37,746		$	23,038		$	71,081

Basic and diluted net income per limited partner unit	$	0.24		$	0.73		$	0.43		$	1.46

Weighted average units outstanding, basic and diluted (in thousands)		51,799			51,663			51,799			48,804


Other data:

Distributions to limited partners (per unit) - (a)	$	0.47		$	0.46		$	1.41		$	1.35
Distributions paid	$	30,877		$	29,841		$	92,631		$	80,199
Distributable cash flow (non-GAAP) - (b)	$	37,214		$	27,960		$	103,431		$	94,919

Coal and natural resource management segment:
Coal royalty tons (in thousands)		8,387			8,496			25,874			24,975
Average coal royalties ($ per ton)	$	3.56		$	3.92		$	3.50		$	3.56
Average net coal royalties ($ per ton) - (c)	$	3.37		$	3.67		$	3.33		$	3.24

Natural gas midstream segment:
System throughput volumes (MMcf)		29,811			27,744			93,433			68,915
Gross margin (in thousands)	$	26,088		$	30,020		$	63,753		$	87,349

(a)	These quarterly distributions are for cash paid during the periods shown and are payable within 45 days after the end of each quarter to unitholders of record and to our general partner.

(b)	See subsequent page for the calculation and description of distributable cash flow.

(c)	The average net coal royalties per ton deducts coal royalties expense, which is incurred primarily in Central Appalachia.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS - unaudited

(in thousands)

	September 30,			December 31,
	2009			2008

Assets
Cash and cash equivalents	$	11,266		$	9,484
Accounts receivable		60,023			73,267
Derivative assets		7,322			30,431
Other current assets		4,252			4,263
Total current assets		82,863			117,445
Property, plant and equipment, net		909,994			895,119
Other long-term assets		215,938			206,255
Total assets	$	1,208,795		$	1,218,819

Liabilities and Partners' Capital
Accounts payable and accrued liabilities	$	56,522		$	71,186
Deferred income		3,043			4,842
Derivative liabilities		10,900			13,585
Total current liabilities		70,465			89,613
Derivative liabilities		4,323			6,915
Other long-term liabilities		22,982			23,509
Long-term debt		628,100			568,100
Partners' capital		482,925			530,682
Total liabilities and partners' capital	$	1,208,795		$	1,218,819

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited
(in thousands)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
Cash flows from operating activities
Net income	$	18,824		$	44,552		$	41,614		$	88,563
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,851			16,903			51,971			41,322
Commodity derivative contracts:
Total derivative losses (gains)		3,668			(14,239	)		14,234			10,552
Cash receipts (payments) to settle derivatives for the period		(314	)		(14,054	)		4,135			(33,279	)
Noncash interest expense		1,416			1,175			3,149			1,543
Equity earnings, net of distributions received		(1,385	)		(1,409	)		(2,456	)		(1,415	)
Other		1,199			(986	)		569			(1,607	)
Changes in operating assets and liabilities		1,608			(10,502	)		3,209			(10,912	)
Net cash provided by operating activities		42,867			21,440			116,425			94,767

Cash flows from investing activities
Acquisitions, net of cash acquired		(27,648	)		(156,791	)		(29,510	)		(253,031	)
Additions to property, plant and equipment		(11,523	)		(16,062	)		(43,781	)		(54,902	)
Other		300			982			872			1,657
Net cash used in investing activities		(38,871	)		(171,871	)		(72,419	)		(306,276	)

Cash flows from financing activities
Proceeds from equity issuance		-			-			-			140,958
Distributions to partners		(31,211	)		(29,841	)		(92,966	)		(80,199	)
Proceeds from borrowings, net		31,000			176,600			60,000			146,000
Other		-			(3,454	)		(9,258	)		(4,074	)
Net cash provided by (used in) financing activities		(211	)		143,305			(42,224	)		202,685

Net increase (decrease) in cash and cash equivalents		3,785			(7,126	)		1,782			(8,824	)
Cash and cash equivalents - beginning of period		7,481			17,832			9,484			19,530
Cash and cash equivalents - end of period	$	11,266		$	10,706		$	11,266		$	10,706

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands, except per unit data)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Reconciliation of GAAP "Net income" to Non-GAAP "Distributable cash flow"
Net income	$	18,824		$	44,552		$	41,614		$	88,563
Depreciation, depletion and amortization		17,851			16,903			51,971			41,322
Commodity derivative contracts:
Derivative losses included in operating income		-			1,503			-			4,128
Derivative losses included in other income		3,668			(15,742	)		14,234			6,424
Cash receipts (payments) to settle derivatives for the period		(314	)		(14,054	)		4,135			(33,279	)
Equity earnings from joint venture, net of distributions		(1,385	)		(1,409	)		(2,456	)		(1,415	)
Other capital expenditures		(1,430	)		(3,793	)		(6,067	)		(10,824	)

Distributable cash flow (a)	$	37,214		$	27,960		$	103,431		$	94,919

Distribution to Partners:

Limited partner units	$	24,345		$	23,827		$	73,035		$	64,862
General partner interest		497			486			1,491			1,323
Incentive distribution rights (b)		6,035			5,528			18,105			14,014

Total cash distribution paid during period	$	30,877		$	29,841		$	92,631		$	80,199

Total cash distribution paid per unit during period	$	0.47		$	0.46		$	1.41		$	1.35

Reconciliation of GAAP "Net income" to Non-GAAP "Net income, as adjusted"
Net income	$	18,824		$	44,552		$	41,614		$	88,563
Adjustments for derivatives:
Derivative losses included in operating income		-			1,503			-			4,128
Derivative (gains) losses included in other income		3,668			(15,742	)		14,234			6,424
Cash receipts (payments) to settle derivatives for the period		(314	)		(14,054	)		4,135			(33,279	)

Net income, as adjusted (c)	$	22,178		$	16,259		$	59,983		$	65,836

Allocation of net income, as adjusted:
General partner's interest in net income, as adjusted	$	6,358		$	6,240		$	18,943		$	17,028
Limited partners' interest in net income, as adjusted	$	15,820		$	10,019		$	41,040		$	48,808

Net income, as adjusted, per limited partner unit, basic and diluted	$	0.30		$	0.19		$	0.78		$	1.00

(a)

Distributable cash flow represents net income plus depreciation, depletion and amortization expenses, plus (minus) derivative losses (gains) included in operating income and other income, plus (minus) cash received (paid) for derivative settlements, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus other capital expenditures. Distributable cash flow is a significant liquidity metric which is an indicator of our ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to our partners. Distributable cash flow is also the quantitative standard used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of publicly traded partnerships. Distributable cash flow is presented because we believe it is a useful adjunct to net cash provided by operating activities under GAAP. Distributable 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, as a measure of liquidity or as an alternative to net income.

(b)	In accordance with our partnership agreement, incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

(c)

Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash changes in the fair value of derivatives. We believe this presentation is commonly used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies in the natural gas midstream industry. We use this information for comparative purposes within the industry. Net income, as adjusted, is not a measure of financial performance under GAAP and should not be considered as a measure of liquidity or as an alternative to net income.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

QUARTERLY SEGMENT INFORMATION - unaudited

(in thousands)

	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
Three Months Ended September 30, 2009

Revenues
Natural gas midstream	$	-	$	118,443	$	118,443
Coal royalties		29,821		-		29,821
Coal services		1,869		-		1,869
Timber		1,582		-		1,582
Oil and gas royalties		535		-		535
Other		1,372		2,003		3,375
Total revenues		35,179		120,446		155,625
Expenses
Cost of midstream gas purchased		-		92,355		92,355
Coal royalties expense		1,587		-		1,587
Other operating		559		6,884		7,443
Taxes other than income		421		584		1,005
General and administrative		3,388		4,180		7,568
Depreciation, depletion and amortization		7,999		9,852		17,851
Total expenses		13,954		113,855		127,809

Operating income	$	21,225	$	6,591	$	27,816

Additions to property and equipment and acquisitions	$	140	$	39,031	$	39,171

	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
Three Months Ended September 30, 2008

Revenues
Natural gas midstream	$	-	$	241,282	$	241,282
Coal royalties		33,308		-		33,308
Coal services		1,815		-		1,815
Timber		1,911		-		1,911
Oil and gas royalties		1,940		-		1,940
Other		2,686		2,334		5,020
Total revenues		41,660		243,616		285,276
Expenses
Cost of midstream gas purchased		-		211,262		211,262
Coal royalties expense		2,125		-		2,125
Other operating		752		6,164		6,916
Taxes other than income		373		596		969
General and administrative		3,321		3,757		7,078
Depreciation, depletion and amortization		8,794		8,109		16,903
Total expenses		15,365		229,888		245,253

Operating income	$	26,295	$	13,728	$	40,023

Additions to property and equipment and acquisitions	$	497	$	172,356	$	172,853

PENN VIRGINIA RESOURCE PARTNERS, L.P.

YEAR-TO-DATE SEGMENT INFORMATION - unaudited

(in thousands)

	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
Nine Months Ended September 30, 2009

Revenues
Natural gas midstream	$	-	$	348,882	$	348,882
Coal royalties		90,448		-		90,448
Coal services		5,502		-		5,502
Timber		4,355		-		4,355
Oil and gas royalties		1,783		-		1,783
Other		6,487		4,346		10,833
Total revenues		108,575		353,228		461,803
Expenses
Cost of midstream gas purchased		-		285,129		285,129
Coal royalties expense		4,380		-		4,380
Other operating		2,200		20,358		22,558
Taxes other than income		1,146		2,062		3,208
General and administrative		10,760		12,661		23,421
Depreciation, depletion and amortization		23,557		28,414		51,971
Total expenses		42,043		348,624		390,667

Operating income	$	66,532	$	4,604	$	71,136

Additions to property and equipment and acquisitions	$	2,046	$	71,245	$	73,291

	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
Nine Months Ended September 30, 2008

Revenues
Natural gas midstream	$	-	$	601,127	$	601,127
Coal royalties		88,911		-		88,911
Coal services		5,518		-		5,518
Timber		5,328		-		5,328
Oil and gas royalties		4,730		-		4,730
Other		6,523		6,458		12,981
Total revenues		111,010		607,585		718,595
Expenses
Cost of midstream gas purchased		-		513,778		513,778
Coal royalties expense		8,034		-		8,034
Other operating		1,488		15,031		16,519
Taxes other than income		1,115		1,902		3,017
General and administrative		9,780		10,559		20,339
Depreciation, depletion and amortization		22,733		18,589		41,322
Total expenses		43,150		559,859		603,009

Operating income	$	67,860	$	47,726	$	115,586

Additions to property and equipment and acquisitions	$	25,186	$	282,747	$	307,933

PENN VIRGINIA RESOURCE PARTNERS, L.P.

GUIDANCE TABLE - unaudited

(dollars and tons in millions)

Penn Virginia Resource Partners, L.P. is providing the following guidance regarding financial and operational expectations for full-year 2009.

	Actual
	First Quarter			Second Quarter			Third Quarter			YTD		Full-Year
	2009			2009			2009			2009		2009 Guidance

Coal and Natural Resource Management Segment:
Coal royalty tons (millions)		8.7			8.7			8.4			25.8		33.0	-	34.0

Revenues:
Average coal royalties per ton (a)	$	3.50			3.43			3.56			3.50		3.35	-	3.45
Average coal royalties per ton, net of coal royalty expense (a)	$	3.36			3.25			3.37			3.33		3.25	-	3.35
Other (b)	$	7.6			5.1			5.4			18.1		23.0	-	24.0

Expenses:
Cash operating expenses (c)	$	5.9			6.6			6.0			18.5		23.5	-	24.0
Depreciation, depletion and amortization	$	7.4			8.2			8.0			23.6		31.0	-	32.0

Capital expenditures:
Expansion and acquisitions (d)	$	1.3			0.6			0.1			2.0		2.0	-	3.0
Other capital expenditures (e)	$	-			-			-			-		0.5	-	1.0
Total segment capital expenditures	$	1.3			0.6			0.1			2.0		2.5	-	4.0

Natural Gas Midstream Segment:
System throughput volumes (MMcf per day) (f)		359			344			324			342		330	-	340

Expenses:
Cash operating expenses (g)	$	11.8			11.6			11.6			35.0		48.0	-	50.0
Depreciation, depletion and amortization	$	9.1			9.5			9.8			28.4		38.0	-	39.0

Capital expenditures:
Expansion and acquisitions (h)	$	11.2			10.3			34.0			55.5		65.0	-	70.0
Other capital expenditures (i)	$	3.3			1.4			1.4			6.1		7.0	-	9.0
Total segment capital expenditures	$	14.5			11.7			35.4			61.6		72.0	-	79.0

Other:
Interest expense:
End of period total debt outstanding	$	595.1			597.1			628.1
Effective Interest rate		3.9	%		4.2	%		4.2	%

These estimates are meant to provide guidance only and are subject to revision as PVR's operating environment changes.

Notes (changes from previous guidance):

(a)	Increased by $0.05 per ton to reflect higher expected sales prices by PVR lessees.

(b)	Decreased by $0.5 million to reflect lower expected other revenues.

(c)	Increased by $1.0 million to reflect higher expected cash operating expenses

(d)	Decreased by $2.5 to $3.0 million to reflect lower expected segment expansion capital expenditures.

(e)	Decreased by $2.5 to $3.0 million to reflect lower expected segment other capital expenditures.

(f)	Decreased by 20 MMcf per day to reflect lower expected system throughput volumes, although processed volumes are expected to increase.

(g)	Decreased by $2.5 to $3.0 million to reflect lower expected segment operating expenses.

(h)	Decreased by $2.0 to $5.0 million to reflect lower expected segment expansion capital expenditures.

(i)	Decreased by $3.0 to $4.5 million to reflect lower expected segment other capital expenditures.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

DERIVATIVE CONTRACT SUMMARY - unaudited

As of September 30, 2009

				Weighted Average Price
	Average			Collars
	Volume Per		Swap	Additional Put
	Day		Price	Option (a)		Put (b)		Call (c)

Crude oil three-way collar - (1)	(barrels)					(per barrel)
Fourth quarter 2009		1,000		$	70.00	$	90.00	$	119.25

Frac spread collar - (2)	(MMBtu)					(per MMBtu)
Fourth quarter 2009		6,000				$	9.09	$	13.94

Crude oil collar	(barrels)					(per barrel)
First quarter 2010 through fourth quarter 2010		750				$	70.00	$	81.25

Crude oil collar	(barrels)					(per barrel)
First quarter 2010 through fourth quarter 2010		1,000				$	68.00	$	80.00

Natural gas purchase swap	(MMBtu)		(MMBtu)
First quarter 2010 through fourth quarter 2010		5,000	$5.815

We estimate that, excluding the derivative positions described above, for every $1.00 MMBtu increase or decrease in the natural gas price, natural gas midstream gross margin and operating income for the remainder of 2009 would decrease or increase by approximately $1.3 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by approximately $1.2 million. This assumes that crude oil prices, natural gas prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

(1) -

A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

(2) -

Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for NGLs that we sell after processing. We hedge against the variability in the frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMBtu basis.

(a) - Sold put.

(b) - Purchased put/floor.