PVR Partners, L. P. 10Q 2008 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2008

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-16735

PENN VIRGINIA RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

23-3087517

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

THREE RADNOR CORPORATE CENTER, SUITE 300

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by a check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨ Yes x No

As of May 8, 2008, 46,106,285 common limited partner units were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX


		Page
PART I.	Financial Information

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income for the Three Months Ended March 31, 2008 and 2007	1

	Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007	2

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2008 and 2007	3

	Notes to Condensed Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	14

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	27

Item 4.	Controls and Procedures	29

PART II.	Other Information

Item 6.	Exhibits	31

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)


	Three Months Ended March 31,
	2008			2007
Revenues
Natural gas midstream	$	125,048		$	95,318
Coal royalties		23,962			25,000
Coal services		1,862			1,601
Other		5,942			2,281

Total revenues		156,814			124,200

Expenses
Cost of midstream gas purchased		99,697			79,731
Operating		6,793			5,514
Taxes other than income		1,072			843
General and administrative		6,518			5,639
Depreciation, depletion and amortization		11,500			10,133

Total expenses		125,580			101,860

Operating income		31,234			22,340

Other income (expense)
Interest expense		(4,932	)		(3,547	)
Interest income		462			287
Derivatives		7,776			(2,647	)

Net income	$	34,540		$	16,433

General partner’s interest in net income	$	4,627		$	2,494

Limited partners’ interest in net income	$	29,913		$	13,939

Basic and diluted net income per limited partner unit (see Note 5)	$	0.55		$	0.30

Weighted average number of units outstanding, basic and diluted		46,106			46,106

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	March 31, 2008			December 31, 2007
Assets
Current assets
Cash and cash equivalents	$	8,329		$	19,530
Accounts receivable		93,665			78,888
Derivative assets		3,779			1,212
Other current assets		4,176			4,104

Total current assets		109,949			103,734

Property, plant and equipment		897,132			877,571
Accumulated depreciation, depletion and amortization		(156,480	)		(146,289	)

Net property, plant and equipment		740,652			731,282

Equity investments		26,001			25,640
Goodwill		7,718			7,718
Intangibles, net		28,067			28,938
Derivative assets		419			—
Other long-term assets		33,446			33,967

Total assets	$	946,252		$	931,279

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	82,614		$	65,483
Accrued liabilities		9,894			10,753
Current portion of long-term debt		13,269			12,561
Deferred income		2,383			2,958
Derivative liabilities		29,338			41,733

Total current liabilities		137,498			133,488
Deferred income		7,858			6,889
Other liabilities		18,812			19,158
Derivative liabilities		4,808			1,315
Long-term debt		400,479			399,153
Partners’ capital		376,797			371,276

Total liabilities and partners’ capital	$	946,252		$	931,279

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended March 31,
	2008			2007
Cash flows from operating activities
Net income	$	34,540		$	16,433
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		11,500			10,133
Commodity derivative contracts:
Total derivative losses (gains)		(6,668	)		3,490
Cash settlements of derivatives		(9,522	)		(2,072	)
Non-cash interest expense		164			165
Equity earnings, net of distributions received		(360	)		(233	)
Other		(309	)		—
Changes in operating assets and liabilities		(499	)		(4,398	)

Net cash provided by operating activities		28,846			23,518

Cash flows from investing activities
Acquisitions, net of cash acquired		(20	)		(339	)
Additions to property, plant and equipment		(17,650	)		(7,002	)
Other		341			43

Net cash used in investing activities		(17,329	)		(7,298	)

Cash flows from financing activities
Distributions to partners		(24,718	)		(21,029	)
Proceeds from borrowings		25,000			10,000
Repayments of borrowings		(23,000	)		(5,000	)
Proceeds from issuance of Class B units		—			860

Net cash used in financing activities		(22,718	)		(15,169	)

Net increase (decrease) in cash and cash equivalents		(11,201	)		1,051
Cash and cash equivalents – beginning of period		19,530			11,440

Cash and cash equivalents – end of period	$	8,329		$	12,491

Supplemental disclosure:
Cash paid for interest	$	6,123		$	4,534

The accompanying notes are an integral part of these condensed consolidated financial statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

March 31, 2008

1.	Organization

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “us” or “our”) is a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. We currently conduct operations in two business segments: (1) coal and natural resource management and (2) natural gas midstream.

Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. We also earn revenues from other land management activities, such as selling standing timber and real estate rentals, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and the panhandle of Texas. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded Delaware limited partnership. Penn Virginia owns an approximately 82% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. PVG owns an approximately 42% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us.

2.	Summary of Significant Accounting Policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2007. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our condensed consolidated financial statements include the accounts of the Partnership and all of its wholly owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Our condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our condensed consolidated financial statements have been included. These financial statements should be read in conjunction with our condensed consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007. Operating results for the three months ended March 31, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. Certain reclassifications have been made to conform to the current period’s presentation.

New Accounting Standards

In March 2008, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards, (“SFAS”) No. 161,Disclosures about Derivative Instruments and Hedging Activities,an Amendment of FASB Statement No. 133, which amends and expands SFAS No. 133,Accounting for Derivative Instruments and HedgingActivities. SFAS No. 161 requires companies to

disclose the fair value of derivative instruments and their gains or losses in tabular format and information about credit-risk-related contingent features in derivative agreements, counterparty credit risk and strategies and objectives for using derivative instruments. SFAS No. 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application permitted. We are currently assessing the impact on the financial statements of adopting SFAS No. 161 effective January 1, 2009.

In March 2008, the Emerging Issues Task Force (“EITF”) ratified EITF Issue No. 07-4, which states that incentive distribution rights (“IDRs”) in a typical master limited partnership are participating securities under SFAS No. 128. Under EITF 07-4, when current-period earnings exceed cash distributions and the IDR is embedded in the general partner interest, undistributed earnings should not be allocated to the general partner (including embedded IDRs) and limited partners. For example, had we applied EITF 07-4, our earnings per unit for the three months ended March 31, 2008 and 2007 would have been $0.65 and $0.30. Under the current accounting guidance, our earnings per unit for the three months ended March 31, 2008 and 2007 was $0.55 and $0.30. See Note 5 – Partners’ Capital and Distributions. EITF 07-4 will be effective for fiscal years beginning after December 15, 2008, and applied retrospectively to all periods presented. Early application is not permitted. We are currently assessing the impact on the financial statements of adopting EITF 07-4 effective January 1, 2009.

3.	Fair Value Measurement of Financial Instruments

We adopted SFAS No. 157,Fair Value Measurements, effective January 1, 2008 for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. FASB Staff Position FAS 157-2,Effective Date of FASB Statement No. 157,delays the application of SFAS 157 for nonfinancial assets and nonfinancial liabilities to periods beginning after November 15, 2008.

SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

•

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

•

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

•

Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

The following table summarizes the valuation of our financial instruments by the above SFAS No. 157 categories as of March 31, 2008:


				Fair Value Measurement at March 31, 2008, Using
Description	Fair Value Measurements, March 31, 2008			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap liability - current	$	(2,515	)	$	—	$	(2,515	)	$	—
Interest rate swap liability - noncurrent		(4,808	)		—		(4,808	)		—
Commodity derivative assets - current		3,779			—		3,779			—
Commodity derivative assets - noncurrent		419			—		419			—
Commodity derivative liability - current		(26,823	)		—		(26,823	)		—

Total	$	(29,948	)	$	—	$	(29,948	)	$	—

We use the following methods and assumptions to estimate the fair values in the above table:

•

Commodity derivative instruments: The fair values of our commodity derivative agreements are determined based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 4 – Derivative Instruments.

•

Interest rate swaps. We have entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”). We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 4 – Derivative Instruments.

4.	Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize costless collar, three-way collar and swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. We also utilize swap derivative contracts to hedge against the variability in our “frac spread.” Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for the natural gas liquids, or NGLs, that we sell after processing. We hedge against the variability in our 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. While the use of derivative instruments limits the risk of adverse price movements, their use also may limit future revenues or cost savings from favorable price movements.

With respect to a costless collar contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

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.

The fair values of our derivative agreements are determined based on forward price quotes for the respective commodities as of March 31, 2008, the credit risks of our counterparties and our own credit risk. The following table sets forth our positions as of March 31, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Fair Value
	Average Volume Per Day		Weighted Average Price			Additional Put Option		Put		Call		Fair Value
Frac Spread	(in MMBtu	)		(per MMBtu	)								(in thousands	)
Second Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(2,902	)

Ethane Sale Swap	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,133	)

Propane Sale Swaps	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,283	)

Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Second Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(7,622	)

Natural Gasoline Collar	(in gallons	)							(per gallon)
Second Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(901	)

Crude Oil Collar	(in barrels	)							(per barrel)
Second Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(2,682	)

Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									3,653

Crude Oil Three-Way Collar	(in barrels	)							(per barrel)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		544

Settlements to be paid in subsequent period													(3,300	)

Natural gas midstream segment commodity derivatives - net liability												$	(22,626	)

At March 31, 2008, we reported a (i) net derivative liability related to the natural gas midstream segment of $22.6 million and (ii) loss in accumulated other comprehensive income of $4.4 million related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006. The $4.4 million loss will be recorded in earnings through the end of 2008 as the hedged transactions settle. The following table summarizes the effects of commodity derivative activities on our condensed consolidated statements of income for the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008			2007
	(in thousands)
Income statement caption:
Natural gas midstream revenues	$	(2,251	)	$	(2,286	)
Cost of midstream gas purchased		1,143			1,443
Derivatives		7,776			(2,647	)

Increase (decrease) in net income	$	6,668		$	(3,490	)

Realized and unrealized derivative impact:
Cash paid for derivative settlements	$	(9,522	)	$	(2,072	)
Unrealized derivative gain (loss)		16,190			(1,418	)

Increase (decrease) in net income	$	6,668		$	(3,490	)

Interest Rate Swaps

We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver. Until March 2010, the notional amounts of the Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $100.0 million. Until March 2010, we will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). From March 2010 to December 2011, we will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest income (expense). We reported a (i) derivative liability of $7.3 million at March 31, 2008 and (ii) loss in accumulated other comprehensive income of $7.3 million at March 31, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.3 million in net hedging gains in interest expense for the three months ended March 31, 2008.

5.	Partners’ Capital and Distributions

As of March 31, 2008, partners’ capital consisted of 46.1 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of March 31, 2008, affiliates of Penn Virginia, in the aggregate, owned a 44% interest in us, consisting of 19.7 million common units and a 2% general partner interest.

Subordinated Units

Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us that were issued to PVG in connection with PVG’s initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.

Net Income per Limited Partner Unit

EITF Issue No. 03-6,Participating Securities and the Two-Class Method under FASB Statement No. 128, addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. EITF Issue No. 03-6 provides that in any accounting period where our net income exceeds our distribution for such period, we are required to present net income per limited partner unit as if all of the net income for the period was distributed, regardless of the pro forma nature of this allocation and whether that net income would actually be distributed during a particular period from an economic or practical perspective. In this instance, basic and diluted net income per limited partner unit is determined by dividing net income available to limited partners by the weighted average number of limited partner units outstanding during the period. To calculate net income available to limited partners, income is first allocated to our general partner based on the amount of incentive distributions to which it is entitled and the remainder is allocated between the limited partners and our general partner based on their percentage ownership interests in us.

We make cash distributions on the basis of cash available for distributions, not net income, in any given accounting period. In accounting periods where our net income does not exceed our distributions for such period, EITF Issue No. 03-6 does not apply and basic and diluted net income per limited partner unit is determined by dividing net income by the weighted average number of limited partner units outstanding during the period.

The following table reconciles net income and weighted average units used in computing basic and diluted net income per limited partner unit:


	Three Months Ended March 31,
	2008			2007
	(in thousands, except per unit data)
Net income	$	34,540		$	16,433
Less: General partner's incentive distributions paid		(4,017	)		(2,210	)

Subtotal		30,523			14,223
General partner interest in net income		(610	)		(284	)

Limited partners' interest in net income		29,913			13,939
Additional earnings allocation to general partner under EITF 03-6		(4,715	)		—

Net income available to limited partners under EITF 03-6	$	25,198		$	13,939

Weighted average limited partner units, basic and diluted		46,106			46,106
Basic and diluted net income per limited partner unit	$	0.55		$	0.30

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business; (ii) comply with applicable law, any of our debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.

According to our partnership agreement, our general partner receives incremental incentive cash distributions if cash distributions exceed certain target thresholds as follows:


	Unitholders		General Partner
Quarterly cash distribution per unit:
First target - up to $0.275 per unit	98	%	2	%
Second target - above $0.275 per unit up to $0.325 per unit	85	%	15	%
Third target - above $0.325 per unit up to $0.375 per unit	75	%	25	%
Thereafter - above $0.375 per unit	50	%	50	%

The following table reflects the allocation of total cash distributions paid by us during the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008		2007
	(in thousands, except per unit data)
Limited partner units	$	20,287	$	18,443
General partner interest (2%)		414		376
Incentive distribution rights		4,017		2,210

Total cash distributions paid	$	24,718	$	21,029

Total cash distributions paid per unit	$	0.44	$	0.40

On February 14, 2008, the board of directors of our general partner paid a $0.44 per unit quarterly distribution ($1.76 per unit on an annualized basis) to unitholders of record on February 4, 2008.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units.

6.	Related-Party Transactions

General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us totaled $1.5 million and $1.1 million for the three months ended March 31, 2008 and 2007. These costs are reflected in general and administrative expenses in our condensed consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable.

Accounts Payable—Affiliate

Amounts payable to related parties totaled $3.7 million and $2.7 million as of March 31, 2008 and 2007. These balances consists primarily of amounts due to Penn Virginia and its affiliates for general and administrative expenses incurred on our behalf and is included in accounts payable on our condensed consolidated balance sheets.

Marketing Revenues

Penn Virginia Oil & Gas, L.P. (“PVOG”), a wholly owned subsidiary of Penn Virginia, and Connect Energy Services, LLC (“Connect Energy”), our wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG and Connect Energy have agreed that Connect Energy will market all of PVOG’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one year terms until terminated by either party. For the three months ended March 31, 2008 and 2007, PVOG paid Connect Energy $0.7 million and $0.4 million in fees pursuant to the Master Services Agreement. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

7.	Unit-Based Compensation

For the three months ended March 31, 2008 and 2007, we recognized a total of $0.7 million and $0.5 million of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan. During the three months ended March 31, 2008, 130,551 restricted units with a weighted average grant date fair value of $26.91 per unit were granted to employees of Penn Virginia and its affiliates. During the same period, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted in 2008 vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

8.	Comprehensive Income

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. The following table sets forth the components of comprehensive income for the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008			2007
	(in thousands)
Net income	$	34,540		$	16,433
Unrealized holding losses on derivative activities		(5,143	)		(200	)
Reclassification adjustment for derivative activities		841			672

Comprehensive income	$	30,238		$	16,905

9.	Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, our management believes that these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.

As of March 31, 2008 and December 31, 2007, our environmental liabilities included $1.4 million and $1.5 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

There are numerous mine health and safety laws and regulations applicable to the coal mining industry. However, since we do not operate any mines and do not employ any coal miners, we are not subject to such laws and regulations. Accordingly, we have not accrued any related liabilities.

10.

Segment Information

Segment information has been prepared in accordance with SFAS No. 131,Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal and natural resource management operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:

•

Coal and Natural Resource Management—management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber and real estate rentals; leasing of fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants; collection of oil and gas royalties; and coal transportation, or wheelage, fees.

•

Natural Gas Midstream—natural gas processing, gathering and other related services.

The following table presents a summary of certain financial information relating to our segments as of and for the three months ended March 31, 2008 and 2007:


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Three Months Ended March 31, 2008:
Revenues	$	30,294	$	126,520	$	156,814
Cost of midstream gas purchased		—		99,697		99,697
Operating costs and expenses		6,299		8,084		14,383
Depreciation, depletion and amortization		6,413		5,087		11,500

Operating income	$	17,582	$	13,652		31,234

Interest expense, net						(4,470	)
Derivatives						7,776

Net income					$	34,540

Total assets	$	598,103	$	348,149	$	946,252
Equity investments	$	25,941	$	60	$	26,001
Additions to property and equipment and acquisitions	$	48	$	17,622	$	17,670

For the Three Months Ended March 31, 2007:
Revenues	$	28,484	$	95,716	$	124,200
Cost of midstream gas purchased		—		79,731		79,731
Operating costs and expenses		5,094		6,902		11,996
Depreciation, depletion and amortization		5,490		4,643		10,133

Operating income	$	17,900	$	4,440		22,340

Interest expense, net						(3,260	)
Derivatives						(2,647	)

Net income					$	16,433

Total assets	$	365,326	$	353,519	$	718,845
Equity investments	$	25,528	$	60	$	25,588
Additions to property and equipment and acquisitions	$	1,336	$	6,005	$	7,341

11.

Subsequent Events

On April 9, 2008, we amended our Revolver to increase the commitments under the Revolver from $450.0 million to $600.0 million.

On April 24, 2008, we acquired a 25% member interest in a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin for $52.0 million in cash, after customary closing adjustments. Funding for the acquisition was provided by borrowings under our Revolver.

Item 2

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

The following discussion and analysis of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us” or “our”) should be read in conjunction with our condensed consolidated financial statements and the accompanying notes in Item 1, “Financial Statements.”

Overview of Business

We are a publicly traded Delaware limited partnership formed by Penn Virginia in 2001 that is principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (1) coal and natural resource management and (2) natural gas midstream. Our operating income was $31.2 million for the three months ended March 31, 2008, compared to $22.3 million for the three months ended March 31, 2007. In the three months ended March 31, 2008, our coal and natural resource management segment contributed $17.6 million, or 56%, to operating income, and our natural gas midstream segment contributed $13.7 million, or 44%, to operating income.

The following table presents a summary of certain financial information relating to our segments:


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Three Months Ended March 31, 2008:
Revenues	$	30,294	$	126,520	$	156,814
Cost of midstream gas purchased		—		99,697		99,697
Operating costs and expenses		6,299		8,084		14,383
Depreciation, depletion and amortization		6,413		5,087		11,500

Operating income	$	17,582	$	13,652	$	31,234

For the Three Months Ended March 31, 2007:
Revenues	$	28,484	$	95,716	$	124,200
Cost of midstream gas purchased		—		79,731		79,731
Operating costs and expenses		5,094		6,902		11,996
Depreciation, depletion and amortization		5,490		4,643		10,133

Operating income	$	17,900	$	4,440	$	22,340

Coal and Natural Resource Management Segment

As of December 31, 2007, we owned or controlled 818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In the three months ended March 31, 2008, our lessees produced 7.6 million tons of coal from our properties and paid us coal royalties revenues of $24.0 million, for an average royalty per ton of $3.14. Approximately 86% of our coal royalties revenues in the three months ended March 31, 2008 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

Coal royalties are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and which may require us, our lessees or our lessee’s customers to change operations significantly or incur substantial costs.

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change, our average royalty per ton also changes because the majority of our lessees pay royalties based on the gross sales prices of the coal mined. Most of our coal is sold by our lessees under contracts with a duration of one year or more; therefore, changes to our average royalty occur as our lessees’ contracts are renegotiated. The global markets for most types of coal remain strong. Continued demand from emerging countries and the increased consumption domestically have created a strong global picture. During 2007, U.S.-produced coal enjoyed increased demand abroad as dwindling supplies and the decline of the dollar made U.S.-exported coal more attractive. Pricing in 2008 is strong primarily due to increasing global demand and supply difficulties.

We also earn revenue from the provision of fee-based coal preparation and loading services, from the sale of standing timber on our properties, from oil and gas royalty interests we own and from coal transportation, or wheelage, fees.

Our management continues to focus on acquisitions that increase and diversify our sources of cash flow.

Natural Gas Midstream Segment

We own and operate natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,716 miles of natural gas gathering pipelines and four natural gas processing facilities having 220 MMcfd of total capacity. We also own a natural gas processing facility in East Texas with 80 MMcfd of total capacity that we expect to commence operations in the second quarter of 2008. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

For the three months ended March 31, 2008, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 17.3 Bcf, or approximately 190 MMcfd. For the three months ended March 31, 2008, two of our natural gas midstream customers accounted for 54% of our natural gas midstream revenues and 44% of our total consolidated revenues.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.

We continually seek new supplies of natural gas to both offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems.

Liquidity and Capital Resources

We generally satisfy our working capital requirements and fund our capital expenditures and debt service obligations from cash generated from our operations and borrowings under our Revolver. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled

debt payments and distribution payments. See Note 5 in the Notes to Condensed Consolidated Financial Statements for a tabular presentation of distribution thresholds. Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance, which will be affected by, among other things, prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control.

Cash Flows

The following table summarizes our cash flow statements for the three months ended March 31, 2008 and 2007 (in thousands):


For the Three Months Ended March 31, 2008	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
Cash flows from operating activities:
Net income contribution	$	12,521		$	22,019		$	34,540
Adjustments to reconcile net income to net cash provided by (used in) operating activities (summarized)		5,891			(11,086	)		(5,195	)
Net change in operating assets and liabilities		(4,418	)		3,919			(499	)

Net cash provided by operating activities	$	13,994		$	14,852			28,846

Net cash provided by (used in) investing activities	$	293		$	(17,622	)		(17,329	)

Net cash used in financing activities								(22,718	)

Net decrease in cash and cash equivalents							$	(11,201	)


For the Three Months Ended March 31, 2007	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
Cash flows from operating activities:
Net income contribution	$	14,453		$	1,980		$	16,433
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		5,421			6,062			11,483
Net change in operating assets and liabilities		(6,767	)		2,369			(4,398	)

Net cash provided by operating activities	$	13,107		$	10,411			23,518

Net cash used in investing activities	$	(1,293	)	$	(6,005	)		(7,298	)

Net cash used in financing activities								(15,169	)

Net increase in cash and cash equivalents							$	1,051

Cash provided by operating activities increased by $5.3 million, or 23%, from $23.5 million in the three months ended March 31, 2007 to $28.8 million in the same period of 2008. The overall increase in cash provided by operating activities in the three months ended March 31, 2007 compared to the same period in 2008 was primarily attributable to the increase in our natural gas midstream segment’s operating income, partially offset by increased cash outflows for derivative settlements.

Capital Expenditures

In the three months ended March 31, 2008 and 2007, we made aggregate capital expenditures of $19.5 and $8.0 million, primarily for natural gas midstream gathering system expansion projects and other natural gas midstream property and equipment expenditures. The following table sets forth capital expenditures by segment made during the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008		2007
	(in thousands)
Coal and natural resource management
Acquisitions	$	20	$	339
Expansion capital expenditures		—		85
Other property and equipment expenditures		28		39

Total		48		463

Natural gas midstream
Expansion capital expenditures		16,373		5,677
Other property and equipment expenditures		3,106		1,907

Total		19,479		7,584

Total capital expenditures	$	19,527	$	8,047

We funded our coal and natural resource management and natural gas midstream capital expenditures in the three months ended March 31, 2008 and 2007 primarily with cash provided by operating activities and borrowings under our Revolver.

Distributions to partners increased to $24.7 million in the three months ended March 31, 2008 from $21.0 million in the three months ended March 31, 2007 because we increased the quarterly unit distribution from $0.40 per unit to $0.44 per unit.

We had net borrowings of $2.0 million in the three months ended March 31, 2008, comprised of net borrowings of $8.0 million under the Revolver and net repayments of $6.0 million under our senior unsecured notes, or Notes. This is compared to $5.0 million of net borrowings in the three months ended March 31, 2007, comprised of net borrowings of $10.0 million under the Revolver and net repayments of $5.0 million under the Notes. Funds from the borrowings in the three months ended March 31, 2008 and 2007 were primarily used for capital expenditures.

Long-Term Debt

As of March 31, 2008, we had outstanding borrowings of $413.7 million, consisting of $355.7 million borrowed under the Revolver and $58.0 million of Notes. The current portion of the Notes as of March 31, 2008 was $13.3 million.

Revolving Credit Facility. As of March 31, 2008, we had $355.7 million outstanding under the Revolver that matures in December 2011. On April 9, 2008, the commitments under the Revolver increased to $600.0 million. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $1.6 million as of March 31, 2008. At the current $600.0 million limit on the Revolver, and given the outstanding balance of $355.7 million, net of $1.6 million of letters of credit, we could borrow up to $242.7 million. In the three months ended March 31, 2008, we incurred commitment fees of less than $0.1 million on the unused portion of the Revolver. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 0.75% if we select the base rate borrowing option under the Revolver or at a rate derived from LIBOR, plus an applicable margin ranging from 0.75% to 1.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver in the three months ended March 31, 2008 was 5.1%.

The financial covenants under the Revolver require us not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions. In addition, the Revolver contains various covenants that limit, among other things, our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. As of March 31, 2008, we were in compliance with all of our covenants under the Revolver.

Senior Unsecured Notes. As of March 31, 2008, we owed $58.0 million under the Notes. The Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The Notes are equal in right of payment with all of our other unsecured indebtedness, including the Revolver. The Notes require us to obtain an annual confirmation of our credit rating, with a 1.00% increase in the interest rate payable on the Notes in the event our credit rating falls below investment grade. In March 2008, our investment grade credit rating was confirmed by Dominion Bond Rating Services. The Notes contain various covenants similar to those contained in the Revolver. As of March 31, 2008, we were in compliance with all of our covenants under the Notes.

Interest Rate Swaps.We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $100.0 million. Until March 2010, we will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, we will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.25% in effect as of March 31, 2008, the total interest rate on the $160.0 million portion of Revolver borrowings covered by the Revolver Swaps was 5.58% at March 31, 2008.

Future Capital Needs and Commitments

Part of our strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to our unitholders. Our ability to make these acquisitions in the future will depend in part on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating. For 2008 projects, we have budgeted capital expenditures, excluding acquisitions, of $15.7 million, consisting of $0.2 million in the coal and natural resource management segment and $15.5 million in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the Revolver. We make quarterly cash distributions of our available cash, generally defined as all of our cash and cash equivalents on hand at the end of each quarter less cash reserves. We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to our general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008		2007
	(in thousands, except per unit data)
Revenues	$	156,814	$	124,200
Expenses	$	125,580	$	101,860

Operating income	$	31,234	$	22,340
Net income	$	34,540	$	16,433
Net income per limited partner unit, basic and diluted	$	0.55	$	0.30
Cash flows provided by operating activities	$	28,846	$	23,518

Operating income increased by $8.9 million in the three months ended March 31, 2008 compared to the same period of 2007 primarily due to a $9.8 million increase in natural gas midstream gross processing margin, a $1.4 million increase in timber revenues and a $1.1 million increase in producer services, partially offset by a $1.3 million increase in operating expenses, a $0.9 million increase in general and administrative expenses and a $1.4 million increase in depreciation, depletion and amortization.

Net income increased by $18.1 million in the three months ended March 31, 2008 compared to the same period in 2007 primarily due to the $8.9 million increase in operating income and a $10.4 million increase in derivative gains, partially offset by a $1.4 million increase in interest expense.

Coal and Natural Resource Management Segment

Three Months Ended March 31, 2008 Compared With the Three Months Ended March 31, 2007

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,						% Change
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	23,962		$	25,000		(4	)%
Coal services		1,862			1,601		16	%
Timber		1,584			179		785	%
Oil and gas royalty		1,234			277		345	%
Other		1,652			1,427		16	%

Total revenues		30,294			28,484		6	%

Expenses
Coal royalties		2,512			1,783		41	%
Other operating		231			372		(38	)%
Taxes other than income		371			323		15	%
General and administrative		3,185			2,616		22	%
Depreciation, depletion and amortization		6,413			5,490		17	%

Total expenses		12,712			10,584		20	%

Operating income	$	17,582		$	17,900		(2	)%

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		7,640			8,284		(8	)%
Average royalties revenues per ton ($/ton)	$	3.14		$	3.02		4	%
Less royalties expense per ton ($/ton)		(0.33	)		(0.22	)	50	%

Average net coal royalties per ton ($/ton)	$	2.81		$	2.80		0	%

Revenues. Coal royalties revenues decreased by $1.0 million, or 4%, from $25.0 million in the three months ended March 31, 2007 to $24.0 million in the same period of 2008. Coal royalties expense increased by $0.7 million, or 41%, from $1.8 million in the three months ended March 31, 2007 to $2.5 million in the same period of 2008. Tons produced by our lessees decreased by 0.7 million tons, or 8%, from 8.3 million tons in the three months ended March 31, 2007 to 7.6 million tons in the same period of 2008. Our average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, remained relatively constant from the three months ended March 31, 2007 to the same period of 2008.

The following table summarizes coal production, coal royalties revenue and coal royalties per ton by region for the three months ended March 31, 2008 and 2007:


	Coal Production		Coal Royalty Revenues						Coal Royalties Per Ton
	Three Months Ended March 31,		Three Months Ended March 31,						Three Months Ended March 31,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,811	4,957	$	18,579		$	18,910		$	3.86		$	3.81
Northern Appalachia	674	1,370		1,134			2,103			1.68			1.54
Illinois Basin	1,033	619		1,938			1,307			1.88			2.11
San Juan Basin	1,122	1,338		2,311			2,680			2.06			2.00

Total	7,640	8,284	$	23,962		$	25,000		$	3.14		$	3.02

Less coal royalties expense (1)				(2,512	)		(1,783	)		(0.33	)		(0.22	)

Net coal royalties revenues			$	21,450		$	23,217		$	2.81		$	2.80

(1)	Our coal royalties expenses are incurred primarily in the Central Appalachian region.

Coal services revenues increased by $0.3 million, or 16%, from $1.6 million in the three months ended March 31, 2007 to $1.9 million in the same period of 2008. This increase is due primarily to increased preparation and loading fees based on continued successes of our lessees operating our coal services facility in Knott County, Kentucky. Timber revenues increased by $1.4 million, or 785%, from $0.2 million in the three months ended March 31, 2007 to $1.6 million in the same period of 2008 primarily due to the effects of our September 2007 forestland acquisition. Oil and gas royalty revenues increased by $0.9 million, or 345%, from $0.3 million in the three months ended March 31, 2007 to $1.2 million in the same period of 2008 primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $0.3 million, or 16%, from $1.4 million in the three months ended March 31, 2007 to $1.7 million in the same period of 2008 primarily due to increased wheelage income in Central Appalachia as well as an overall increase in minimum rental income.

Expenses.General and administrative expenses increased by $0.6 million, or 22%, from $2.6 million in the three months ended March 31, 2007 to $3.2 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $0.9 million, or 17%, from $5.5 million in the three months ended March 31, 2007 to $6.4 million in the same period of 2008 primarily due to increased depletion resulting from our forestland acquisition in September 2007 and our oil and gas royalty interest acquisition in October 2007.

Natural Gas Midstream Segment

Three Months Ended March 31, 2008 Compared With the Three Months Ended March 31, 2007

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the three months ended March 31, 2008 and 2007:


	Three Months Ended March 31,
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	61,667		$	59,680		3	%
Natural gas liquids		56,197			31,988		76	%
Condensate		6,216			2,916		113	%
Gathering and transportation fees		968			734		32	%

Total natural gas midstream revenues		125,048			95,318		31	%
Producer services		1,472			398		270	%

Total revenues		126,520			95,716		32	%

Expenses
Cost of midstream gas purchased		99,697			79,731		25	%
Operating		4,050			3,359		21	%
Taxes other than income		701			520		35	%
General and administrative		3,333			3,023		10	%
Depreciation and amortization		5,087			4,643		10	%

Total operating expenses		112,868			91,276		24	%

Operating income	$	13,652		$	4,440		207	%

Operating Statistics
System throughput volumes (MMcf)		17,287			15,900		9	%
System throughput volumes (MMcf/day)		190			177		7	%
Gross processing margin	$	25,351		$	15,587		63	%
Impact of derivatives		(8,414	)		(1,229	)	585	%

Gross processing margin, adjusted for impact of derivatives	$	16,937		$	14,358		18	%

Gross processing margin ($/MMcf)	$	1.47		$	0.98		50	%
Impact of derivatives ($/MMcf)		(0.49	)		(0.08	)	513	%

Gross processing margin, adjusted for impact of derivatives ($/MMcf)	$	0.98		$	0.90		9	%

Gross Processing Margin. Our gross processing margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Natural gas midstream revenues included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. Cost of midstream gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage-of-proceeds and gas purchase/keep-whole contracts.

Natural gas midstream revenues increased by $29.7 million, or 31%, from $95.3 million in the three months ended March 31, 2007 to $125.0 million in the same period of 2008. Cost of midstream gas purchased increased by $20.0 million, or 25%, from $79.7 million in the three months ended March 31, 2007 to $99.7 million in the same period of 2008. Our gross processing margin increased by $9.8 million, or 63%, from $15.6 million in the three months ended March 31, 2007 to $25.4 million in the same period of 2008. The gross processing margin increase was a result of an increased pricing environment, increased system throughput volumes and higher fractionation, or “frac” spreads during the three months ended March 31, 2008 compared to the same period of 2007. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 13 MMcfd, or 7%, from 177 MMcfd in the three months ended March 31, 2007 to 190 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the continued successful development by producers operating in the vicinity of our systems, as well as our success in contracting and connecting new supply. We also increased our processing capacity with the addition of the Spearman plant in the three months ended March 31, 2008.

During the three months ended March 31, 2008, we generated a majority of our gross processing margin from contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Adjusted for the impact of derivative financial instruments, our gross

processing margin increased by $2.5 million, or 18%, from $14.4 million for the three months ended March 31, 2007 to $16.9 million for the same period of 2008. On a per MMcf basis, the gross processing margin adjusted for the impact of derivatives increased by $0.08, or 9%, from $0.90 per MMcf in the three months ended March 31, 2007 to $0.98 per MMcf in the same period of 2008.

Producer Services Revenues.Producer services revenues increased by $1.1 million, or 270%, from $0.4 million in the three months ended March 31, 2007 to $1.5 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production.

Expenses. Total operating costs and expenses increased primarily due to increases in operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.

Operating expenses increased by $0.7 million, or 21%, from $3.4 million in the three months ended March 31, 2007 to $4.1 million in the same period of 2008 primarily due to expenses related to our expanding footprint in areas of operation, including the addition of the Spearman plant. General and administrative expenses increased by $0.3 million, or 10%, from $3.0 million in the three months ended March 31, 2007 to $3.3 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $0.4 million, or 10%, from $4.7 million in the three months ended March 31, 2007 to $5.1 million in the same period of 2008. This increase is primarily due to the addition of the Spearman plant, as well as an $11.9 million increase in segment capital expenditures, from $7.6 million in the three months ended March 31, 2007 to $19.5 million in the same period of 2008.

Other

Our other results consist of interest expense and derivative gains and losses.

Interest Expense. Interest expense increased by $1.4 million, or 39%, from $3.5 million in the three months ended March 31, 2007 to $4.9 million in the same period of 2008. We also capitalized $0.5 million of interest costs in the three months ended March 31, 2008 related to the construction of our natural gas gathering facilities in East Texas. We had no capitalized interest in the three months ended March 31, 2007. This increase in interest cost is primarily due to the increase in our average debt balance, which increased from $221.8 million at March 31, 2007 to $412.5 million at March 31, 2008.

Derivatives. Derivative activity changed from a $2.6 million loss in the three months ended March 31, 2007 to a $7.8 million gain in the same period of 2008. The derivative losses in the three months ended March 31, 2008 consisted of a $17.3 million unrealized gain for changes in fair value and a $9.5 realized loss. The derivative losses in the three months ended March 31, 2007 consisted of a $0.5 million unrealized loss for changes in fair value and a $2.1 million realized loss.

Summary of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.

Natural Gas Midstream Revenues

We recognize revenues from the sale of NGLs and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which have historically not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

Coal Royalties Revenues

We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

Derivative Activities

Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we recognized the deferred changes in fair value in revenues and cost of gas purchased in our condensed consolidated statements of income. As of March 31, 2008, we had $4.4 million of net losses remaining in accumulated other comprehensive income. We will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). Because we no longer use hedge accounting for our commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to swings in the value of these contracts. Our results of operations are affected by the potential volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. These fluctuations could be significant in a volatile pricing environment.

Depletion

Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists and coal reserve engineers. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. We deplete timber on an area-by-area basis at a rate based upon the quantity of timber sold. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves.

Goodwill

Under SFAS No. 141,Business Combinations, and SFAS No. 142,Goodwill and Other Intangible Assets, goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. Accordingly, we do not amortize goodwill. We test goodwill for impairment during the fourth quarter of each fiscal year.

Intangible Assets

Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 15 years, the period in which benefits are derived from the contracts, relationships and rights-of-way, and are reviewed for impairment under SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets.

Fair Value Measurements

SFAS No. 157 requires fair value measurement to be classified and disclosed in one of the following three categories:

•

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

•

Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

We use the following methods and assumptions to estimate the fair values of financial instruments:

•

Commodity derivative instruments: The fair values of our derivative agreements are determined based on forward price quotes for the respective commodities. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 4 – Derivative Instruments.

•

Interest rate swaps: We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under our Revolver. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. Each of these is a level 2 input. See Note 4 – Derivative Instruments.

Environmental Matters

Recent Accounting Pronouncements

See Note 2 in the Notes to Condensed Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

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;

•

the relationship between natural gas, coal and NGL 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 market) and political conditions (including the impact of potential terrorist attacks); and

•

other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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, 2007. 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.

Item 3

Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are natural gas, NGL, crude oil and coal price risks and interest rate risk.

We are also indirectly exposed to the credit risk of our customers and lessees. If our customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations.

Price Risk Management

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of minimum credit risk. The fair values of our price risk management activities are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

For the three months ended March 31, 2008, we reported a net derivative gain of $7.8 million. Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we recognized the deferred changes in fair value in revenues and cost of gas purchased in our condensed consolidated statements of income. As of March 31, 2008, we had $4.4 million of net losses remaining in accumulated other comprehensive income. We will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). Because we no longer use hedge accounting for its commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to swings in the value of these contracts. Our results of operations are affected by the potential volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. These fluctuations could be significant in a volatile pricing environment.

The following table lists our derivative agreements and their fair values as of March 31, 2008:


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Fair Value
	Average Volume Per Day		Weighted Average Price			Additional Put Option		Put		Call		Fair Value
Frac Spread	(in MMBtu	)		(per MMBtu	)								(in thousands	)
Second Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(2,902	)

Ethane Sale Swap	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,133	)

Propane Sale Swaps	(in gallons	)		(per gallon	)
Second Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,283	)

Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Second Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(7,622	)

Natural Gasoline Collar	(in gallons	)							(per gallon)
Second Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(901	)

Crude Oil Collar	(in barrels	)							(per barrel)
Second Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(2,682	)

Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
First Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									3,653

Crude Oil Three-Way Collar	(in barrels	)							(per barrel)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		544

Settlements to be paid in subsequent period													(3,300	)

Natural gas midstream segment commodity derivatives - net liability												$	(22,626	)

We estimate that excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in natural gas prices from the $7.50 per MMBtu budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income in 2008 would increase or decrease by approximately $7.2 million. This assumes oil and other liquids prices and inlet volumes remain constant at budgeted levels. In addition, we also estimate that excluding the derivative positions described above, for every $5.00 per barrel increase or decrease in the oil prices from the $80.00 per barrel budgeted 2008 benchmark price, natural gas midstream gross processing margin and operating income would increase or decrease by approximately $3.2 million. This assumes natural gas prices and inlet volumes remain constant at budgeted levels. These estimated changes in gross processing margin and operating income exclude the potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of March 31, 2008, we had $355.7 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps to effectively convert the interest rate on $160.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.33% plus the applicable margin until March 2010. From March 2010 to December 2011, the Revolver Swaps will effectively convert the interest rate on $100.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.40% plus the applicable margin. The Revolver Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) at March 31, 2008 would cost us approximately $2.0 million in additional interest expense.

Item 4

Controls and Procedures

(a)

Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 2008. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of March 31, 2008, such disclosure controls and procedures were effective.

(b)

Changes in Internal Control Over Financial Reporting

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

PART II. OTHER INFORMATION

Item 1

Legal Proceedings

Loadout LLC (“Loadout”), a subsidiary of ours, holds permits (which have been assigned to a mine operator who leases the property for mining) to mine at the Nellis Surface Mine in Boone County, West Virginia. The U.S. Army Corps of Engineers (“Corps”) issued a permit under Section 404 of the federal Clean Water Act to Loadout on April 16, 2008, authorizing the placement of fill material into certain waters of the United States in conjunction with the construction of four valley fills, three sediment pond embankments and one haul road at the Nellis Mine. On April 23, 2008, the plaintiffs in the suitOhio Valley Environmental Coalition v. U.S. Army Corps of Engineers, No. 3:05-0784 (S.D. W. Va.) filed a complaint and motion for a temporary restraining order (“TRO”) seeking to suspend or revoke the Corps’ Section 404 permit, alleging, among other things, violations by the Corps of the National Environmental Policy Act and Clean Water Act. The plaintiffs have since filed a motion to withdraw their motion for a TRO on April 30, 2008, pending good-faith negotiations between the plaintiffs, Loadout, and Loadout’s designated operator, Coal River Mining, LLC, to reach an agreement over the Nellis Section 404 permit. Because of the limited volume of projected coal to be produced from the Nellis Surface Mine relative to total production from all our holdings, it is not expected that either a settlement of this matter or possible delay in proceeding with mining pending litigation would materially affect our business interests.

Item 6

Exhibits


3.1		Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Penn Virginia Resource Partners, L.P. dated April 15, 2008 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed on April 16, 2008).

4.1		Fourth Amendment to Note Purchase Agreement dated March 26, 2008 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 4.1 to Registrant’s Current Report on Form 8-K filed on March 31, 2008).

10.1		Sixth Amendment, Waiver and Consent to Amended and Restated Credit Agreement dated March 14, 2008 among Penn Virginia Operating Co., LLC, the Guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other Lenders party thereto, and in their stated capacities.

10.2		Seventh Amendment to Amended and Restated Credit Agreement, dated April 9, 2008, among Penn Virginia Operating Co., LLC, the Guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other Lenders party thereto, and in their stated capacities (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on April 11, 2008).

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

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

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

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

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

SIGNATURES

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


	PENN VIRGINIA RESOURCE PARTNERS, L.P.

	By: PENN VIRGINIA RESOURCE GP, LLC

Date: May 9, 2008	By:	/s/ Frank A. Pici
		Frank A. Pici
		Vice President and Chief Financial Officer

Date: May 9, 2008	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Good

PVR Partners, L. P. (PVR) Inactive 10-Q2008 Q1 Quarterly report

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