PVR Partners, L. P. (PVR) 8-K Record 2005 Results and 2006 Guidance

Exhibit 99

Penn Virginia Resource Partners, L.P.

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

FOR IMMEDIATE RELEASE

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. ANNOUNCES

RECORD 2005 RESULTS AND 2006 GUIDANCE

NEW ANNUAL RECORDS SET FOR DISTRIBUTABLE CASH FLOW,

OPERATING INCOME AND NET INCOME

RADNOR, PA (Businesswire) February 8, 2006 – Penn Virginia Resource Partners, L.P. (NYSE:PVR) today reported record annual distributable cash flow of $82.6 million for 2005, an increase of 56 percent compared to $52.9 million reported for 2004. Operating income for 2005 was a record $76.9 million, compared to $40.5 million for 2004. Net income for 2005 was a record $50.0 million, or $2.38 per limited partner unit, compared to net income of $34.3 million, or $1.86 per limited partner unit, for 2004. The increases in distributable cash flow, a non-GAAP measure, operating income and net income were primarily attributable to increased coal royalty revenues resulting from higher commodity prices and related services income, and the contribution of PVR’s natural gas midstream business that was acquired in the first quarter of 2005. The increase in 2005 net income was reduced by increased interest expense and by non-cash unrealized losses on derivatives. A reconciliation of distributable cash flow and other non-GAAP financial measures appears in the financial tables later in this news release.

For the fourth quarter of 2005, distributable cash flow was $21.4 million, an increase of 67 percent over $12.8 million for the same quarter of 2004. Operating income was $19.7 million in the fourth quarter of 2005 as compared to $11.2 million in the same quarter of 2004. Net income was $13.2 million, or $0.61 per limited partner unit, for the fourth quarter of 2005, compared with net income of $8.6 million, or $0.46 per limited partner unit, for the fourth quarter of 2004. As was the case with the full-year results for 2005, the increases in the fourth quarter 2005 results were primarily due to increased coal segment revenues and the contribution of PVR’s natural gas midstream business acquired in the first quarter of 2005. The increase in fourth quarter 2005 net income was reduced by increased interest expense and by non-cash unrealized losses on derivatives.

Cash Distribution

As previously announced, PVR will pay a quarterly cash distribution covering the period October 1 through December 31, 2005, in the amount of $0.70 per unit, or an annualized rate of $2.80 per unit, on February 14, 2006, to unit holders of record as of February 3, 2006. This represents an eight percent increase over the distribution of $0.65 per unit, or an annualized rate of $2.60, for the third quarter of 2005 and a 24 percent increase over the $0.5625 per unit distribution for the fourth quarter of 2004.

Management Comment

A. James Dearlove, Chief Executive Officer of PVR, said, “We had another record year in 2005, setting new highs for distributable cash flow, operating income and net income. The decision in January 2006 by our general partner’s Board of Directors to increase PVR’s quarterly distribution payable in February 2006 by eight percent over the distribution for the third quarter of 2005 reflects PVR’s strong cash position and our confidence in the future.

“During 2005, worldwide and domestic demand for coal continued to be very strong. High natural gas prices helped keep coal firmly entrenched as the fuel of choice for domestic electricity generation. Benefiting from strong coal pricing, PVR’s average royalties per ton in 2005 were 23 percent higher than in 2004. We completed four coal reserve acquisitions during 2005, adding approximately 152 million tons of coal for a total acquisition cost of approximately $100 million. Approximately 58 million of those tons consist of high quality coal located in central Appalachia, where we have owned coal reserves since 1882. Approximately 94 million tons of the coal we acquired is in the western Kentucky portion of the Illinois Basin, which is a new area for us. We view the Illinois Basin as a growth area due to its proximity to power plants and because we expect future environmental regulations will require scrubbing of most coals, including lower sulfur coals from other basins. We expect to continue to diversify our coal reserve holdings into this and other domestic basins in the future. We are also continuing to expand our coal infrastructure business by constructing a new preparation plant and train loading facility on one of our newly acquired central Appalachian properties.

“Our natural gas gathering and processing business located in Texas and Oklahoma, which we operate as PVR Midstream, provided the Partnership with significant additional distributable cash flow and operating income in 2005. PVR Midstream has the critical mass of people and assets to be a growth platform for PVR. The natural gas midstream sector is well suited to PVR’s master limited partnership structure and includes an abundance of potential acquisition opportunities. We expect to grow PVR Midstream from organic sources, such as by tying new natural gas production to our existing systems, and through acquisitions of other midstream assets.”

Coal Segment Review

Full-year 2005 operating income in the coal segment was a record $62.0 million, or 53 percent higher than the $40.5 million reported in 2004. Revenues increased to $95.8 million in 2005 from $75.6 million in 2004, mainly as a result of increased coal royalty revenues, which increased to $82.7 million in 2005, a 19 percent increase over $69.6 million in 2004. Higher coal prices were the primary reason for increased average royalty per ton, up 23 percent to $2.74 in 2005 from $2.23 in 2004. Coal production from PVR properties decreased to 30.2 million tons in 2005 from 31.2 million tons in 2004, primarily due to reduced production from a lessee’s longwall mining operation which moved off of one of PVR’s subleased central Appalachian properties, and from reduced production on PVR’s property in New Mexico. The production decreases were partially offset by production from newly acquired properties in the western Kentucky portion of the Illinois Basin. Coal services revenues increased by 37 percent to $5.2 million in 2005 from $3.8 million in 2004, driven by increased equity earnings from its coal handling joint venture and from two coal handling facilities that began operating in July 2003 and February 2004. Other revenues also increased to $7.8 million in 2005 from $2.2 million in 2004, primarily due to additional coal transportation-related fees, oil and gas royalty revenues resulting from 2005 acquisitions and $1.5 million from a one-time sale of a bankruptcy claim filed against a former lessee.

Expenses decreased from $35.1 million in 2004 to $33.8 million in 2005, due primarily

to lower operating expenses and depreciation, depletion and amortization (DD&A) resulting from lower coal production, offset in part by higher general and administrative expenses resulting from higher payroll and compliance-related expenses.

Fourth quarter 2005 operating income in the coal segment was $16.8 million, or 50 percent higher than the $11.2 million reported in the fourth quarter of 2004. The primary reason for the improved operating income was increased revenues resulting from higher coal production, including the new Illinois Basin property, a 19 percent increase in the average royalty per ton and an increase in other revenues from 2005 acquisitions, offset in part by higher payroll-related general and administrative expenses.

Natural Gas Midstream Segment Review

Ten-month and fourth quarter 2005 operating income in the natural gas midstream segment acquired in March 2005 from Cantera Gas Resources, LLC (the “Cantera Acquisition”) was $14.9 million and $2.9 million. Inlet volumes at the midstream segment’s gas processing plants and gathering systems were approximately 38.9 billion cubic feet (Bcf), or approximately 127 million cubic feet per day, for the ten months in 2005 and 11.9 Bcf, or approximately 129 million cubic feet per day, during the fourth quarter. Gross processing margin, consisting of midstream revenues minus the cost of gas purchased, was $43.1 million, or $1.11 per thousand cubic feet of plant inlet gas, for the 10 months in 2005 and $12.0 million, or $1.01 per thousand cubic feet, during the fourth quarter. Expenses other than cost of gas purchased were $30.1 million for the 10 months and $9.6 million for the fourth quarter.

Capital Resources and Impact of Derivatives

As of December 31, 2005, PVR’s outstanding borrowings were $255.0 million, including $8.1 million of senior unsecured notes classified as current portion of long-term debt, up from $117.7 million as of December 31, 2004. The increase in outstanding borrowings was due to the Cantera Acquisition and coal property acquisitions completed in 2005. As a result of the debt increase, interest expense, net, increased from $2.6 million in the fourth quarter of 2004 to $3.6 million for the fourth quarter of 2005 and from $6.2 million in 2004 to $12.9 million for full-year 2005.

Net income for the fourth quarter and full-year 2005 decreased by $2.8 million and $14.0 million due to non-cash unrealized losses on derivatives. During the fourth quarter and full-year 2005, the ineffectiveness of open commodity price hedges related to PVR’s natural gas midstream business and an adjustment related to a basis swap that follows mark-to-market accounting contributed to the unrealized derivative losses. Also affecting the full-year results was a charge for mark-to-market adjustments on certain derivative agreements related to the Cantera Acquisition. As part of the Cantera Acquisition, PVR supported the acquisition economics by entering into pre-closing commodity price hedging agreements covering approximately 75 percent of the net volume of natural gas liquids expected to be sold from April 2005 through December 2006. Rising commodity prices resulted in a change in the market value of those derivative agreements before they qualified for hedge accounting. This change in market value resulted in PVR recognizing a $13.9 million non-cash charge to earnings for the unrealized loss on derivatives during the first quarter of 2005.

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 PVR’s operating environment changes.

Conference Call

A conference call and webcast, at which management will discuss fourth quarter 2005 results and the outlook for 2006, is scheduled for Thursday, February 9, 2006, at 1:00 p.m. EST. 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 Internet webcast by logging on to PVR’s 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 telephone replay of the conference call will be available until February 10, 2006, at 11:59 p.m. EST by dialing 1-877-660-6853 and using replay passcodes: account number 286 and conference number 189300. An on-demand replay of the call will also be available at PVR’s website beginning shortly after the call.

*****

Penn Virginia Resource Partners, L.P. (NYSE: PVR) is a master limited partnership formed by Penn Virginia Corporation (NYSE: PVA). The Partnership manages coal properties and related assets and operates a midstream natural gas gathering and processing business. PVR is headquartered in Radnor, PA. For more information about PVR, visit the Partnership’s 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: our ability to generate sufficient cash from our midstream and coal businesses to pay the minimum quarterly distribution; energy prices generally and, specifically, the respective prices of natural gas, NGLs and coal; the relationship between natural gas and NGL prices; the relationship between the price of coal and the prices of natural gas and oil; the volatility of commodity prices for coal, natural gas and NGLs; the projected supply of and demand for coal, natural gas and NGLs; the ability to successfully integrate and manage our new midstream business; the ability to acquire new coal reserves on satisfactory terms; the price for which new coal reserves can be acquired; the ability to lease new and existing coal reserves; the ability to continually find and contract for new sources of natural gas supply; the ability to retain our existing or acquire new midstream customers; the ability of our coal lessees to produce sufficient quantities of coal on an economic basis from our reserves; the ability of our coal lessees to obtain favorable contracts for coal produced from our reserves; competition among producers in the coal industry generally and among midstream companies; the exposure we have to the credit risk of our coal lessees and our midstream customers; the experience and financial condition of our coal lessees, including their ability to satisfy their royalty, environmental, reclamation and other obligations to us and others; the ability to expand our midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner; the extent to which the amount and quality of actual coal production differs from estimated recoverable proved coal reserves; unanticipated geological problems; the dependence of our midstream business on having connections to third party pipelines; availability of required materials and equipment; the occurrence of unusual weather or operating conditions, including force majeure events; the failure of our coal infrastructure or our coal lessees’ mining equipment or processes to operate in accordance with specifications or expectations; delays in anticipated start-up dates of our coal lessees’ mining operations and related coal infrastructure projects; environmental risks affecting the mining of coal reserves and the production, gathering and processing of natural gas; the timing of receipt of necessary governmental permits by our coal 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; uncertainties relating to the outcome of litigation regarding permitting of the disposal of coal overburden; 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); coal handling joint venture operations; and changes in financial market conditions. Additional information concerning these and other factors can be found in and PVR’s press releases and public periodic filings with the Securities and Exchange Commission, including PVR’s Annual Report on Form 10-K for the year ended December 31, 2004, filed on March 1, 2005, and subsequently filed interim reports. Many of the factors that will determine PVR’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. PVR 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 RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME - unaudited

(in thousands, except per share data)

	Three Months Ended December 31,						Year Ended December 31,
	2005			2004			2005			2004
Revenues
Natural gas midstream	$	133,650		$	—		$	347,000		$	—
Coal royalties		21,804			17,248			82,725			69,643
Coal services		1,361			1,008			5,230			3,787
Other		3,672			1,282			9,736			2,200
		160,487			19,538			444,691			75,630
Expenses
Cost of gas purchased		121,633			—			303,912			—
Operating		4,372			1,650			15,102			7,224
Taxes other than income		740			195			2,397			948
General and administrative		5,650			2,271			15,719			8,307
Depreciation, depletion and amortization		8,391			4,247			30,628			18,632
		140,786			8,363			367,758			35,111
Operating Income		19,701			11,175			76,933			40,519
Interest expense, net		(3,623	)		(2,603	)		(12,905	)		(6,204	)
Unrealized loss on derivatives		(2,838	)		—			(14,024	)		—
Net income	$	13,240		$	8,572		$	50,004		$	34,315
Allocation of net income:
General partner’s interest in net income	$	563		$	171		$	2,073		$	686
Limited partners’ interest in net income	$	12,677		$	8,401		$	47,931		$	33,629
Basic and diluted net income per limited partner unit, common and subordinated	$	0.61		$	0.46		$	2.38		$	1.86
Weighted average units outstanding:
Common		16,360			11,700			14,732			10,739
Subordinated		4,462			6,375			5,419			7,331
Other data:
Coal royalty tons (in thousands)		7,731			7,316			30,227			31,181
Average gross coal royalty ($ per ton)	$	2.82		$	2.36		$	2.74		$	2.23
Inlet volumes (MMcf)		11,912			—			38,875			—
Midstream processing margin ($ per Mcf)	$	1.01		$	—		$	1.11		$	—

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2005		December 31, 2004
	(unaudited)
Assets
Cash	$	23,193	$	20,997
Receivables		76,398		8,668
Derivative assets		10,235		—
Other current assets		2,724		541
Total current assets		112,550		30,206
Property and equipment, net		458,782		221,615
Equity investments		26,672		27,881
Goodwill		7,718		—
Intangibles, net		38,051		—
Derivative assets		8,536		—
Other long-term assets		5,570		4,733
Total assets	$	657,879	$	284,435
Liabilities and Partners’ Capital
Current portion of long-term debt	$	8,108	$	4,800
Accounts payable and accrued liabilities		69,009		3,989
Derivative liabilities		20,700		—
Other current liabilities		2,325		1,207
Total current liabilities		100,142		9,996
Derivative liabilities		11,246		774
Other long-term liabilities		16,843		10,755
Long-term debt		246,846		112,926
Partners’ capital		282,802		149,984
Total liabilities and partners’ capital	$	657,879	$	284,435

CONSOLIDATED STATEMENTS OF CASH FLOWS - unaudited

(in thousands)

	Three Months Ended December 31,						Year Ended December 31,
	2005			2004			2005			2004
Operating Activities
Net income	$	13,240		$	8,572		$	50,004		$	34,315
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		8,391			4,247			30,628			18,632
Unrealized loss on derivatives		2,838			—			14,024			—
Noncash interest expense		216			1,300			1,735			1,678
Equity earnings, net of distributions		(277	)		726			1,269			561
Changes in operating assets and liabilities		(1,576	)		1,214			(2,709	)		(404	)
Net cash provided by operating activities		22,832			16,059			94,951			54,782
Investing Activities
Acquisitions, net of cash acquired		(551	)		—			(291,318	)		(28,442	)
Additions to property and equipment		(4,149	)		(149	)		(13,594	)		(1,088	)
Other		—			519			52			1,104
Net cash provided by (used in) investing activities		(4,700	)		370			(304,860	)		(28,426	)
Financing Activities
Payments for debt issuance costs		—			(1,234	)		(2,385	)		(1,234	)
Proceeds from borrowings, net		(3,000	)		—			137,200			26,000
Proceeds from issuance of partners’ capital		(19	)		—			129,239			—
Distributions to partners		(14,137	)		(9,962	)		(51,949	)		(39,191	)
Net cash provided by (used in) financing activities		(17,156	)		(11,196	)		212,105			(14,425	)
Net increase in cash and cash equivalents		976			5,233			2,196			11,931
Cash and cash equivalents-beginning balance		22,217			15,764			20,997			9,066
Cash and cash equivalents-ending balance	$	23,193		$	20,997		$	23,193		$	20,997

PENN VIRGINIA RESOURCE PARTNERS, L.P.

QUARTER SEGMENT INFORMATION - unaudited

(Dollars in thousands except where noted)

			Natural Gas Midstream (1)
	Coal		Amount		(per Mcf)		Consolidated
Three months ended December 31, 2005
Revenues
Natural gas midstream	$	—	$	133,650			$	133,650
Coal royalties		21,804		—				21,804
Coal services		1,361		—				1,361
Other		3,161		511				3,672
Total revenues		26,326		134,161	$	11.26		160,487
Expenses
Cost of gas purchased		—		121,633		10.21		121,633
Operating		1,651		2,721		0.23		4,372
Taxes other than income		402		338		0.03		740
General and administrative		3,025		2,625		0.22		5,650
Depreciation, depletion and amortization		4,450		3,941		0.33		8,391
Total expenses		9,528		131,258		11.02		140,786
Operating Income	$	16,798	$	2,903	$	0.24	$	19,701
Production
Coal royalty tons (thousands of tons)		7,731
Inlet volumes (MMcf)				11,912
Additions to property and equipment and acquisitions, net of cash acquired	$	1,699	$	3,001			$	4,700
			Natural Gas Midstream (1)
	Coal		Amount		(per Mcf)		Consolidated
Three months ended December 31, 2004
Revenues
Natural gas midstream	$	—	$	—			$	—
Coal royalties		17,248		—				17,248
Coal services		1,008		—				1,008
Other		1,282		—				1,282
Total revenues		19,538		—	$	—		19,538
Expenses
Cost of gas purchased		—		—		—		—
Operating		1,650		—		—		1,650
Taxes other than income		195		—		—		195
General and administrative		2,271		—		—		2,271
Depreciation, depletion and amortization		4,247		—		—		4,247
Total expenses		8,363		—		—		8,363
Operating Income	$	11,175	$	—	$	—	$	11,175
Production
Coal royalty tons (thousands of tons)		7,316
Additions to property and equipment and acquisitions, net of cash acquired	$	149	$	—			$	149

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

PENN VIRGINIA RESOURCE PARTNERS, L.P.

FULL YEAR SEGMENT INFORMATION - unaudited

(Dollars in thousands except where noted)

			Natural Gas Midstream (1)
Year ended December 31, 2005	Coal		Amount		(per Mcf)		Consolidated
Revenues
Natural gas midstream	$	—	$	347,000			$	347,000
Coal royalties		82,725		—				82,725
Coal services		5,230		—				5,230
Other		7,800		1,936				9,736
Total revenues		95,755		348,936	$	8.98		444,691
Expenses
Cost of gas purchased		—		303,912		7.82		303,912
Operating		5,755		9,347		0.24		15,102
Taxes other than income		1,129		1,268		0.03		2,397
General and administrative		8,987		6,732		0.17		15,719
Depreciation, depletion and amortization		17,890		12,738		0.33		30,628
Total expenses		33,761		333,997		8.59		367,758
Operating Income	$	61,994	$	14,939	$	0.38	$	76,933
Production
Coal royalty tons (thousands of tons)		30,227
Inlet volumes (MMcf)				38,875
Additions to property and equipment and acquisitions, net of cash acquired (2)	$	112,497	$	206,811			$	319,308
			Natural Gas Midstream (1)
Year ended December 31, 2004	Coal		Amount		(per Mcf)		Consolidated
Revenues
Natural gas midstream	$	—	$	—			$	—
Coal royalties		69,643		—				69,643
Coal services		3,787		—				3,787
Other		2,200		—				2,200
Total revenues		75,630		—	$	—		75,630
Expenses
Cost of gas purchased		—		—		—		—
Operating		7,224		—		—		7,224
Taxes other than income		948		—		—		948
General and administrative		8,307		—		—		8,307
Depreciation, depletion and amortization		18,632		—		—		18,632
Total expenses		35,111		—		—		35,111
Operating Income	$	40,519	$	—	$	—	$	40,519
Production
Coal royalty tons (thousands of tons)		31,181
Additions to property and equipment and acquisitions, net of cash acquired (3)	$	2,148	$	—			$	2,148

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

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

(3) Coal segment includes noncash expenditures of $1.1 million.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

RECONCILIATION OF CERTAIN NON-GAAP FINANCIAL MEASURES - unaudited

(in thousands)

	Three Months Ended December 31,						Year Ended December 31,
	2005			2004			2005			2004
Reconciliation of GAAP “Net income” to Non-GAAP “Distributable cash flow”
Net income	$	13,240		$	8,572		$	50,004		$	34,315
Depreciation, depletion and amortization		8,391			4,247			30,628			18,632
Unrealized loss (gain) on derivatives, net of settlements		395			—			6,595			—
Other property and equipment expenditures		(615	)		(20	)		(4,615	)		(70	)
Distributable cash flow (see Note 1 below)	$	21,411		$	12,799		$	82,612		$	52,877
Reconciliation of GAAP “Net income” to Non-GAAP “EBITDA”
Net income	$	13,240		$	8,572		$	50,004		$	34,315
Interest expense, net		3,623			2,603			12,905			6,204
Depreciation, depletion and amortization		8,391			4,247			30,628			18,632
EBITDA (see Note 2 below)	$	25,254		$	15,422		$	93,537		$	59,151
Reconciliation of GAAP “Additions to property and equipment” to Non-GAAP “Capital expenditures”
Additions to property and equipment	$	4,149		$	149		$	13,594		$	1,088
Acquisitions, net of cash acquired		551			—			291,318			28,442
Noncash lease acquisitions		—			—			14,396			1,060
Capital expenditures (see Note 3 below)	$	4,700		$	149		$	319,308		$	30,590

Note 1 - Distributable cash flow represents net income before depreciation, depletion and amortization expense and unrealized loss on derivatives (net of settlements of first quarter $13.9 million loss), minus other capital expenditures. Other property and equipment expenditures are capital expenditures (as defined by GAAP) which do not increase the capacity of an asset or generate additional revenues or net cash from operating activities. Distributable 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). Distributable cash flow is a significant liquidity metric which is an indicator of PVR’s ability to generate cash flows at a level that can sustain or support an increase in quarterly cash distributions paid to its partners. Distributable cash flow is also the quantitative standard used throughout the investment community with respect to publicly-traded partnerships. 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 or as a measure of liquidity.

Note 2 - EBITDA represents net income before interest expense and depreciation, depletion and amortization expense. Management believes EBITDA provides additional, useful information regarding PVR’s ability to meet our debt service, capital expenditure and working capital requirements. EBITDA is a traditional measure of a business’ ability to generate cash flows irrespective of financing costs and is presented as a supplemental financial measurement in the evaluation of our business. This measure is widely used by investors and rating agencies in the valuation, comparison, rating and investment recommendations of companies. EBITDA is the most widely-used financial measure by commercial banks, investment bankers, fixed-income investors and ratings agencies. It is also a financial measurement that, with certain negotiated adjustments, is reported to our banks under our bank credit facility and is used in our financial covenants under our bank credit facility and the indenture governing our senior unsecured notes. EBITDA is not a measure of financial performance under GAAP. Accordingly, it should not be considered as a substitute for net income, income from operations or net cash flows provided by operating activities prepared in accordance with GAAP.

Note 3 - Capital expenditures represents cash additions to property and equipment, plus cash paid for acquisitions and other expenditures. 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 Resource Partners, L.P.

Guidance Table

(Dollars and tons in millions)

Penn Virginia Resource Partners, L.P. is providing the following guidance regarding financial and operational expectations for 2006.

	Actual					Guidance
	Fourth Quarter 2005			YTD 2005		Full Year 2006
Coal Segment:
Coal royalty tons (millions)		7.7		30.2		31.5		—	34.5
Revenues:
Average coal royalty per ton	$	2.82		2.74		2.65		—	2.75
Other	$	4.5		13.0		12.0		—	14.0
Expenses:
Direct expenses	$	5.1		15.9		15.0		—	17.0
Depreciation, depletion and amortization	$	4.5		17.9		21.0		—	23.0
Capital Expenditures:
Coal segment acquisitions	$	1.0		106.5				N/A
Coal segment other expenditures	$	1.1		6.0		16.0		—	18.0
Total Coal Capital Expenditures	$	2.1		112.5
Natural Gas Midstream Segment: (a)
Inlet volumes (MMcf per day) - (b)		129		127		115		—	130
Expenses:
Direct expenses	$	5.7		17.3		19.0		—	22.0
Depreciation, depletion and amortization	$	3.9		12.7		14.0		—	16.0
Capital Expenditures:
Midstream segment acquisitions, net of cash acquired	$	0.1		199.2				N/A
Midstream segment other expenditures	$	2.9		7.6		8.0		—	10.0
Total Midstream Capital Expenditures	$	3.0		206.8
Other:
Interest expense:
Average long-term debt outstanding	$	256.4		209.2		250.0		—	260.0
Interest rate		5.2	%	5.6	%	5.5	%	—	6.0	%

These estimates are meant to provide guidance only and are subject to revision as the operating environment of Penn Virginia Resource Partners, L.P. changes.

Notes:

(a) Actual results and full year guidance include the natural gas midstream segment from the date of the Cantera Acquisition in March 2005.

(b) The natural gas midstream segment’s ethane and propane (revenues), crude oil (revenues) and natural gas (cost of gas purchased) hedging positions as of December 31, 2005, are summarized below:

	Average Volume Per Day	Weighted Average Price
	(gallons)	(per gallon)
Ethane Swaps
First Quarter 2006 - Fourth Quarter 2006	68,800	$	0.4770
First Quarter 2007 - Fourth Quarter 2007	34,440	$	0.5050
First Quarter 2008 - Fourth Quarter 2008	34,440	$	0.4700
	(gallons)	(per gallon)
Propane Swaps
First Quarter 2006 - Fourth Quarter 2006	52,080	$	0.7060
First Quarter 2007 - Fourth Quarter 2007	26,040	$	0.7550
First Quarter 2008 - Fourth Quarter 2008	26,040	$	0.7175
	(Bbls)	(per Bbl)
Crude Oil Swaps
First Quarter 2006 - Fourth Quarter 2006	1,100	$	44.45
First Quarter 2007 - Fourth Quarter 2007	560	$	50.80
First Quarter 2008 - Fourth Quarter 2008	560	$	49.27
	(Mmbtu)	(per Mmbtu)
Natural Gas Swaps
First Quarter 2006 - Fourth Quarter 2006	7,500	$	7.05
First Quarter 2007 - Fourth Quarter 2008	4,000	$	6.97