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 SECOND QUARTER 2009 RESULTS

RADNOR, PA (BusinessWire) August 5, 2009 – Penn Virginia Resource Partners, L.P. (NYSE: PVR) today reported financial and operational results for the three months ended June 30, 2009 and provided an update of full-year 2009 guidance.

Second Quarter 2009 Highlights

Second quarter 2009 highlights and results, with comparisons to second quarter 2008 results, included the following:

Distributable cash flow (DCF), a non-GAAP (generally accepted accounting principles) measure, of $34.6 million, as compared to a quarterly record $40.6 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 $17.9 million, or $0.22 per limited partner unit, as compared to a quarterly record $31.2 million, or $0.52 per limited partner unit, in the prior year quarter;

Net income of $13.3 million, or $0.13 per limited partner unit, as compared to $9.5 million, or $0.08 per limited partner unit;

Coal production by lessees of 8.7 million tons, as compared to 8.8 million tons;

Coal royalties revenue, net of coal royalties expense, of $28.4 million, or $3.25 per ton, as compared to $28.2 million, or $3.20 per ton;

Quarterly natural gas midstream system throughput volumes of 31.3 billion cubic feet (Bcf), or 344 million cubic feet (MMcf) per day, as compared to 23.9 Bcf, or 262 MMcf per day;

Midstream gross margin, prior to the cash impact of derivatives, of $20.9 million, or $0.67 per Mcf, as compared to a record $32.0 million, or $1.34 per Mcf; and

Midstream gross margin, adjusted for the cash impact of midstream derivatives, of $24.3 million, or $0.77 per thousand cubic feet (Mcf), as compared to $23.8 million, or $1.00 per Mcf.

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

DCF for the second quarter of 2009 of $34.6 million was $5.9 million, or 15 percent lower, than $40.6 million of DCF in the second quarter of 2008 primarily due to:

a $3.0 million decrease in operating income (before depreciation, depletion and amortization (DD&A) expense) from the coal and natural resource management segment (PVR Coal & Natural Resource Management) primarily due to decreases in oil and gas royalties, timber and other revenue and increased general and administrative (G&A) expense;

a $3.7 million decrease in operating income (adjusted for the cash impact of midstream derivatives and before DD&A expense) from the natural gas midstream segment (PVR Midstream), primarily due to a decrease in other revenues and increased operating and G&A expense;

a $1.8 million increase in cash paid to settle interest rate derivatives.

These decreases in DCF were partially offset by a $2.6 million decrease in maintenance capital expenditures. DCF in the second quarter of 2009 was $3.1 million, or 10 percent, higher than the $31.6 million of DCF in the first quarter of 2009 primarily due to improved midstream segment gross margin.

The $13.3 million, or 43 percent, decrease in adjusted net income as compared to the prior year quarter was primarily due to a $7.7 million decrease in operating income from PVR Midstream adjusted for the cash impact of midstream derivatives, a $3.7 million decrease in operating income from PVR Coal & Natural Resource Management and the $1.8 million increase in cash paid to settle interest rate derivatives.

The $3.9 million, or 41 percent, increase in net income as compared to the prior year quarter was due to a $27.9 million decrease in derivatives expense resulting from changes in the valuation of unrealized derivative positions, partially offset by a $22.9 million decrease in operating income, a $1.0 million increase in interest expense and a $0.1 million decrease in other income.

Cash Distribution

As previously announced, on August 14, 2009, we will pay to unitholders of record as of August 3, 2009 a quarterly cash distribution of $0.47 per unit, or an annualized rate of $1.88 per unit, covering the period of April 1 through June 30, 2009. On an annualized basis, this represents an approximate two percent increase over the annualized distribution of $1.84 per unit with respect to the same quarter of 2008 and is unchanged from the distribution paid with respect to each of the previous three quarters.

Management Comment

A. James Dearlove, Chief Executive Officer of PVR, said, “While comparisons to our record second quarter of 2008 are generally unfavorable primarily due to lower commodity prices, we are pleased to report that distributable cash flow generated by our two business segments increased by $3.1 million, or 10 percent, over the first quarter of 2009.

“The significant improvement in sequential quarter results was largely due to PVR Midstream, as fractionation spreads improved over the first quarter of 2009 due to higher natural gas liquids (NGLs) prices and lower costs for purchased natural gas.

“Coal royalties revenue net of coal royalties expense, which accounted for approximately 85 percent of the Coal and Natural Resource Management segment’s second quarter revenues, remained relatively stable with respect to production and within our expectations with respect to average coal royalties per ton. Other revenues, which accounted for the remaining 15 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, although spot prices and prices for metallurgical coal – a small proportion of our royalties revenue – have weakened considerably.

“As of June 30, 2009, we had approximately $200 million of unused borrowing capacity under our revolving credit facility, which we believe provides adequate capital to support modest growth opportunities. For example, we recently announced a $28 million expansion of our largest midstream gathering and processing system, which increased our overall processing capacity by one-third. We continue to review growth projects for both segments and, despite recent challenges and the uncertainty in the market, we remain confident in the long-term fundamental characteristics of our business.”

Coal and Natural Resource Management Segment Review

During the second quarter of 2009, operating income for PVR Coal & Natural Resource Management decreased by $3.7 million, or 15 percent, to $20.3 million from $24.0 million in the prior year quarter. Total revenues, net of coal royalties expense, decreased by $2.2 million, or six percent, to $33.5 million from

$35.7 million in the prior year quarter primarily due to a $1.0 million, or 65 percent, decrease in oil and gas royalties revenue resulting from lower commodity prices, as well as reduced timber and other revenues. As compared to the first quarter of 2009, total revenues, net of coal royalties expense, decreased by $3.5 million, or nine percent, primarily due to a $2.3 million decrease in forfeited minimum rentals and a $1.0 million, or three percent, decrease in coal royalties revenue, net of coal royalties expense.

Coal royalties revenue, net of coal royalties expense, was relatively flat compared to the prior year quarter as a 0.1 million ton, or one percent, decrease in lessee production to 8.7 million tons from 8.8 million tons in the prior year quarter was offset by in increase in average net coal royalties per ton of $0.05, or two percent, to $3.25 in the second quarter of 2009 as compared to $3.20 in the prior year quarter. Lessee production decreased in Central Appalachia, partially offset by a lessee production increase in the San Juan Basin. While total lessee production in Central Appalachia decreased from 10.0 to 9.3 million tons, most of the decrease occurred on subleased properties from which we make lower margins per ton produced. Lessee production in Northern Appalachia and the Illinois Basin remained flat as compared to the prior year quarter. Operating expenses, excluding coal royalties expense, increased by 13 percent to $13.2 million primarily due to higher G&A and DD&A expenses.

Natural Gas Midstream Segment Review

During the second quarter, operating income for PVR Midstream decreased to $1.1 million from $20.3 million in the prior year quarter. Midstream gross margin decreased by 35 percent to $20.9 million, or $0.67 per Mcfe, from $32.0 million, or $1.34 per Mcf, in the prior year quarter primarily due to a significant decrease in the price of NGLs as a result of reduced demand, partially offset by a significant increase in system throughput volumes. Adjusted for the cash impact of derivatives, midstream gross margin was $24.3 million, or $0.77 per Mcf, up two percent from $23.8 million, or $1.00 per Mcf, in the prior year quarter and up 18 percent from $20.6 million, or $0.64 per Mcf, in the first quarter of 2009.

System throughput volumes at our gas processing plants and gathering systems increased 31 percent to 31.3 Bcf, or approximately 344 MMcf per day, in the second quarter of 2009 from 23.9 Bcf, or approximately 262 MMcf per day, in the prior year quarter. The volumes increased primarily as a result of contributions from expansions and acquisitions completed in 2008, as well as successful results by producers connected to our gathering systems. System throughput volumes in the second quarter were 15 MMcf per day, or three percent, lower than the 359 MMcf per day in the first quarter of 2009. Other expenses increased by $6.8 million, or 47 percent, to $21.1 million, primarily due to higher operating, G&A and DD&A expenses resulting from acquisitions and increased system throughput volumes.

Capital Resources and Impact of Derivatives

As of June 30, 2009, we had outstanding borrowings of $597.1 million under our $800 million revolving credit facility and $7.5 million of cash and equivalents, with remaining revolver borrowing capacity of approximately $200 million. The $29.0 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 half of 2009. Interest expense increased from $5.4 million in the second quarter of 2008 to $6.4 million in the second quarter of 2009 due to the higher level of outstanding borrowings during the quarter as compared to the prior year quarter.

For the second quarter of 2009, derivatives expense was $2.0 million, as compared to derivatives expense of $29.9 million in the prior year quarter. Cash settlements of derivatives included in these amounts resulted in net cash receipts of $1.6 million during the second quarter of 2009 related to commodity and interest rate derivatives, as compared to $9.7 million of net cash payments in the prior year quarter, an $11.3 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 June 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 second quarter 2009 financial and operational results for PVR and Penn Virginia GP Holdings, L.P. (NYSE: PVG), is scheduled for Thursday, August 6, 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 1-877-407-9205 five to ten minutes before the scheduled start of the conference call, 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 of the call will be available until August 20, 2009 at 11:59 p.m. ET by dialing 1-877-660-6853 and using the following replay pass codes: account #286, conference ID #327734. An on-demand replay of the conference call will be available at our website beginning shortly after the call.

******

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, crude oil 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 business; 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						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Revenues
Natural gas midstream	$	113,060		$	234,797		$	230,439		$	359,845
Coal royalties		29,997			31,641			60,627			55,603
Coal services		1,745			1,841			3,633			3,703
Other		4,617			8,226			11,479			14,168
Total revenues		149,419			276,505			306,178			433,319

Expenses
Cost of midstream gas purchased		92,154			202,819			192,774			302,516
Coal royalties expense		1,569			3,397			2,793			5,909
Operating		7,449			5,322			15,115			9,603
Taxes other than income		980			976			2,203			2,048
General and administrative		8,257			6,743			15,853			13,261
Depreciation, depletion and amortization		17,617			12,919			34,120			24,419
Total expenses		128,026			232,176			262,858			357,756

Operating income		21,393			44,329			43,320			75,563

Other income (expense)
Interest expense		(6,365	)		(5,374	)		(11,981	)		(10,306	)
Interest income and other		328			458			646			920
Derivatives		(2,034	)		(29,942	)		(9,195	)		(22,166	)

Net income	$	13,322		$	9,471		$	22,790		$	44,011

Allocation of net income:
General partner's interest in net income	$	6,181		$	5,607		$	12,285		$	10,677
Limited partners' interest in net income	$	7,141		$	3,864		$	10,505		$	33,334

Basic and diluted net income per limited partner unit	$	0.13		$	0.08		$	0.20		$	0.70

Weighted average units outstanding, basic (in thousands)		51,799			48,581			51,799			47,521
Weighted average units outstanding, diluted (in thousands)		51,887			48,581			51,874			47,521


Other data:
Distributions to limited partners (per unit) (a)	$	0.47		$	0.46		$	0.94		$	0.91
Distributions paid	$	30,877		$	25,640		$	61,754		$	50,358
Distributable cash flow (non-GAAP) (b)	$	34,637		$	40,575		$	66,218		$	66,959

Coal and natural resource management segment:
Coal royalty tons (in thousands)		8,739			8,839			17,487			16,479
Average coal royalties ($ per ton)	$	3.43		$	3.58		$	3.47		$	3.37
Average net coal royalties ($ per ton) (c)	$	3.25		$	3.20		$	3.31		$	3.01

Natural gas midstream segment:
System throughput volumes (MMcf)		31,342			23,884			63,622			41,171
Gross margin (in thousands)	$	20,906		$	31,978		$	37,665		$	57,329

(a)	These quarterly distributions are for the periods shown and are payable within 45 days after the end of each quarter to unitholdersof 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)

	June 30,		December 31,
	2009		2008

Assets
Cash and cash equivalents	$	7,481	$	9,484
Accounts receivable		62,448		73,267
Derivative assets		11,478		30,431
Other current assets		4,668		4,263
Total current assets		86,075		117,445
Property, plant and equipment, net		892,944		895,119
Other long-term assets		211,125		206,255
Total assets	$	1,190,144	$	1,218,819

Liabilities and partners' capital
Accounts payable and accrued liabilities	$	58,630	$	71,186
Deferred income		2,987		4,842
Derivative liabilities		12,278		13,585
Total current liabilities		73,895		89,613
Derivative liabilities		3,949		6,915
Other long-term liabilities		22,247		23,509
Long-term debt		597,100		568,100
Partners' capital		492,953		530,682
Total liabilities and partners' capital	$	1,190,144	$	1,218,819

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
Cash flows from operating activities
Net income	$	13,322		$	9,471		$	22,790		$	44,011
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization		17,617			12,919			34,120			24,419
Commodity derivative contracts:
Total derivative losses		2,951			31,459			10,566			24,791
Cash receipts (payments) to settle derivatives		1,613			(9,703	)		4,449			(19,225	)
Noncash interest expense		1,242			204			1,733			368
Equity earnings, net of distributions received		488			354			(1,071	)		(6	)
Other		(335	)		(312	)		(630	)		(621	)
Changes in operating assets and liabilities		2,287			89			1,601			(410	)
Net cash provided by operating activities		39,185			44,481			73,558			73,327

Cash flows from investing activities
Acquisitions, net of cash acquired		(606	)		(96,220	)		(1,862	)		(96,240	)
Additions to property, plant and equipment		(15,208	)		(21,190	)		(32,258	)		(38,840	)
Other		307			334			572			675
Net cash used in investing activities		(15,507	)		(117,076	)		(33,548	)		(134,405	)

Cash flows from financing activities
Proceeds from equity issuance		-			140,958			-			140,958
Distributions to partners		(30,878	)		(25,640	)		(61,755	)		(50,358	)
Proceeds from borrowings, net		2,000			(32,600	)		29,000			(30,600	)
Other		-			(620	)		(9,258	)		(620	)
Net cash provided by (used in) financing activities		(28,878	)		82,098			(42,013	)		59,380

Net increase (decrease) in cash and cash equivalents		(5,200	)		9,503			(2,003	)		(1,698	)
Cash and cash equivalents - beginning of period		12,681			8,329			9,484			19,530
Cash and cash equivalents - end of period	$	7,481		$	17,832		$	7,481		$	17,832

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands, except per unit data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008

Reconciliation of GAAP "Net income" to Non-GAAP
"Distributable cash flow"
Net income	$	13,322		$	9,471		$	22,790		$	44,011
Depreciation, depletion and amortization		17,617			12,919			34,120			24,419
Commodity derivative contracts:
Derivative losses included in operating income		-			1,517			-			2,625
Derivative losses included in other income		2,951			29,942			10,566			22,166
Cash receipts (payments) to settle derivatives		1,613			(9,703	)		4,449			(19,225	)
Equity earnings from joint venture, net of distributions		488			354			(1,071	)		(6	)
Maintenance capital expenditures		(1,354	)		(3,925	)		(4,636	)		(7,031	)

Distributable cash flow (a)	$	34,637		$	40,575		$	66,218		$	66,959

Distributions to partners:
Limited partner units	$	24,345		$	20,748		$	48,690		$	41,035
General partner interest		497			423			994			837
Incentive distribution rights (b)		6,035			4,469			12,070			8,486

Total cash distributions paid during period	$	30,877		$	25,640		$	61,754		$	50,358

Total cash distribution paid per unit during period	$	0.47		$	0.45		$	0.94		$	0.89


Reconciliation of GAAP "Net income" to Non-GAAP
"Net income as adjusted"
Net income as reported	$	13,322		$	9,471		$	22,790		$	44,011
Adjustments for derivatives:
Derivative losses included in operating income		-			1,517			-			2,625
Derivative losses included in other income		2,951			29,942			10,566			22,166
Cash receipts (payments) to settle derivatives		1,613			(9,703	)		4,449			(19,225	)

Net income as adjusted (c)	$	17,886		$	31,227		$	37,805		$	49,577

Allocation of net income, as adjusted:
General partner's interest in net income, as adjusted	$	6,272		$	6,042		$	12,585		$	10,788
Limited partners' interest in net income, as adjusted	$	11,614		$	25,185		$	25,220		$	38,789

Net income as adjusted, per limited partner unit, basic and diluted	$	0.22		$	0.52		$	0.48		$	0.82

(a)

Distributable cash flow represents net income plus depreciation, depletion and amortization expenses, plus impairments, plus derivative losses (gains) included inoperating income and other income, plus cash received (paid) for derivative settlements, less equity earnings in joint ventures, plus cash distributions from joint ventures, less maintenance 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, ratings 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 ofavailable 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 thispresentation 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. Management uses 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 June 30, 2009

Revenues
Natural gas midstream	$	-	$	113,060	$	113,060
Coal royalties		29,997		-		29,997
Coal services		1,745		-		1,745
Timber		1,456		-		1,456
Oil and gas royalties		545		-		545
Other		1,401		1,215		2,616
Total revenues		35,144		114,275		149,419
Expenses
Cost of midstream gas purchased		-		92,154		92,154
Coal royalties expense		1,569		-		1,569
Other operating		758		6,691		7,449
Taxes other than income		300		680		980
General and administrative		4,020		4,237		8,257
Depreciation, depletion and amortization		8,164		9,453		17,617
Total expenses		14,811		113,215		128,026

Operating income	$	20,333	$	1,060	$	21,393

Additions to property and equipment and acquisitions	$	606	$	15,208	$	15,814


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
Three months ended June 30, 2008

Revenues
Natural gas midstream	$	-	$	234,797	$	234,797
Coal royalties		31,641		-		31,641
Coal services		1,841		-		1,841
Timber		1,833		-		1,833
Oil and gas royalties		1,556		-		1,556
Other		2,185		2,652		4,837
Total revenues		39,056		237,449		276,505
Expenses
Cost of midstream gas purchased		-		202,819		202,819
Coal royalties expense		3,397		-		3,397
Other operating		505		4,817		5,322
Taxes other than income		371		605		976
General and administrative		3,274		3,469		6,743
Depreciation, depletion and amortization		7,526		5,393		12,919
Total expenses		15,073		217,103		232,176

Operating income	$	23,983	$	20,346	$	44,329

Additions to property and equipment and acquisitions	$	24,641	$	92,769	$	117,410

PENN VIRGINIA RESOURCE PARTNERS, L.P.

YEAR-TO-DATE SEGMENT INFORMATION - unaudited

(in thousands)

	Coal and Natural Resource Management		Natural Gas Midstream			Consolidated
Six months ended June 30, 2009

Revenues
Natural gas midstream	$	-	$	230,439		$	230,439
Coal royalties		60,627		-			60,627
Coal services		3,633		-			3,633
Timber		2,773		-			2,773
Oil and gas royalties		1,248		-			1,248
Other		5,115		2,343			7,458
Total revenues		73,396		232,782			306,178
Expenses
Cost of midstream gas purchased		-		192,774			192,774
Coal royalties expense		2,793		-			2,793
Other operating		1,641		13,474			15,115
Taxes other than income		725		1,478			2,203
General and administrative		7,372		8,481			15,853
Depreciation, depletion and amortization		15,558		18,562			34,120
Total expenses		28,089		234,769			262,858

Operating income	$	45,307	$	(1,987	)	$	43,320

Additions to property and equipment and acquisitions	$	1,906	$	32,214		$	34,120


	Coal and Natural Resource Management		Natural Gas Midstream			Consolidated
Six months ended June 30, 2008

Revenues
Natural gas midstream	$	-	$	359,845		$	359,845
Coal royalties		55,603		-			55,603
Coal services		3,703		-			3,703
Timber		3,417		-			3,417
Oil and gas royalties		2,790		-			2,790
Other		3,837		4,124			7,961
Total revenues		69,350		363,969			433,319
Expenses
Cost of midstream gas purchased		-		302,516			302,516
Coal royalties expense		5,909		-			5,909
Other operating		736		8,867			9,603
Taxes other than income		742		1,306			2,048
General and administrative		6,459		6,802			13,261
Depreciation, depletion and amortization		13,939		10,480			24,419
Total expenses		27,785		329,971			357,756

Operating income	$	41,565	$	33,998		$	75,563

Additions to property and equipment and acquisitions	$	24,689	$	110,391		$	135,080

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			YTD		Full-Year
	2009			2009			2009		2009 Guidance

Coal and Natural Resource Management Segment:
Coal royalty tons (millions)		8.7			8.7			17.4		33.0	-	34.0

Revenues:
Average coal royalties per ton (a)	$	3.50			3.43			3.47		3.30	-	3.40
Average coal royalties per ton, net of coal royalty expense (a)	$	3.36			3.25			3.31		3.20	-	3.30
Other (b)	$	7.6			5.1			12.7		23.5	-	24.5

Expenses:
Cash operating expenses (c)	$	5.9			6.6			12.5		22.0	-	23.0
Depreciation, depletion and amortization (d)	$	7.4			8.2			15.6		31.0	-	32.0

Capital expenditures:
Expansion and acquisitions (e)	$	1.3			0.6			1.9		5.0	-	5.5
Maintenance capital expenditures	$	-			-			-		1.0	-	2.0
Total segment capital expenditures	$	1.3			0.6			1.9		6.0	-	7.5

Natural Gas Midstream Segment:
System throughput volumes (MMcf per day)		359			344			352		350	-	360

Expenses:
Cash operating expenses (f)	$	11.8			11.6			23.4		51.0	-	52.5
Depreciation, depletion and amortization	$	9.1			9.5			18.6		38.0	-	39.0

Capital expenditures:
Expansion and acquisitions (g)	$	11.2			10.3			21.5		70.0	-	72.0
Maintenance capital expenditures (h)	$	3.3			1.4			4.7		11.5	-	13.0
Total segment capital expenditures	$	14.5			11.7			26.2		81.5	-	85.0

Other:
Interest expense:
End of period total debt outstanding	$	595.1			597.1
Effective Interest rate		3.9	%		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)	Decreased by $0.05 per ton to reflect expected lower sales prices by PVR lessees.

(b)	Increased $0.5 to $1.0 million to reflect higher expected coal services and other revenues.

(c)	Increased the lower end of guidance by $0.5 million.

(d)	Decreased $0.5 million to reflect lower expected depreciation, depletion and amortization expense.

(e)	Increased $0.5 to $1.0 million to reflect higher expected capital expenditures.

(f)	Decreased the higher end of guidance by $0.5 million.

(g)	Increased by $24.0 million primarily to include the cost of a midstream acquisition in July 2009.

(h)	Decreased $0.5 to $1.0 million to reflect lower expected maintenance capital expenditures.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

DERIVATIVE CONTRACT SUMMARY - unaudited

As of June 30, 2009

	Average Volume Per Day		Weighted Average Price
			Collars
			Additional Put Option (A )		Put (B )		Call (C )

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

Frac spread collar (2)	(MMBtu)				(per MMBtu)
Third quarter 2009 through 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

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 $2.5 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, natural gas midstream gross margin and operating income for the remainder of 2009 would increase or decrease by approximately $2.4 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 thatwe 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 thatwe 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.

(C)	Sold call/ceiling.