PVR Partners, L. P. (PVR) 10-Q 2007 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, 2007

or

¨ 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer   ¨     Accelerated filer  x    Non-accelerated filer   ¨

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 1, 2007, 42,060,974 common and 4,045,311 Class B 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, 2007 and 2006	1
	Condensed Consolidated Balance Sheets as of March 31, 2007 and December 31, 2006	2
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2007 and 2006	3
	Notes to Condensed Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	11
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	24
Item 4.	Controls and Procedures	26
PART II.	Other Information
Item 6.	Exhibits	27

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,
	2007			2006
Revenues
Natural gas midstream	$	95,318		$	109,181
Coal royalties		25,000			22,422
Coal services		1,601			1,426
Other		2,281			2,135
Total revenues		124,200			135,164
Expenses
Cost of midstream gas purchased		79,731			98,651
Operating		5,514			3,478
Taxes other than income		843			698
General and administrative		5,639			5,270
Depreciation, depletion and amortization		10,133			8,821
Total expenses		101,860			116,918
Operating income		22,340			18,246
Other income (expense)
Interest expense		(3,547	)		(4,067	)
Interest income		287			294
Derivatives		(2,647	)		(6,133	)
Net income	$	16,433		$	8,340
General partner’s interest in net income	$	2,494		$	510
Limited partners’ interest in net income	$	13,939		$	7,830
Basic and diluted net income per limited partner unit, common, Class B and subordinated	$	0.30		$	0.19
Weighted average number of units outstanding, basic and diluted:
Common		42,061			33,994
Class B		4,045			—
Subordinated		—			7,650

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

	March 31, 2007			December 31, 2006
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	12,491		$	11,440
Accounts receivable		71,071			66,987
Derivative assets		4,533			449
Other current assets		2,349			2,587
Total current assets		90,444			81,463
Property, plant and equipment		671,239			665,135
Accumulated depreciation, depletion and amortization		(117,559	)		(108,622	)
Net property, plant and equipment		553,680			556,513
Equity investments		25,588			25,355
Goodwill		7,718			7,718
Intangibles, net		31,885			33,045
Derivative assets		2,092			2,455
Other long-term assets		7,438			7,474
Total assets	$	718,845		$	714,023
Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	64,206		$	63,253
Current portion of long-term debt		11,839			10,832
Deferred income		7,283			6,999
Derivative liabilities		11,778			6,996
Total current liabilities		95,106			88,080
Deferred income		3,745			6,592
Other liabilities		3,324			3,339
Derivative liabilities		6,505			6,618
Long-term debt		211,248			207,214
Partners’ capital		398,917			402,180
Total liabilities and partners’ capital	$	718,845		$	714,023

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended March 31,
	2007			2006
Cash flows from operating activities
Net income	$	16,433		$	8,340
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,133			8,821
Commodity derivative contracts:
Total derivative losses		3,490			5,872
Cash settlements of derivatives		(2,072	)		(2,922	)
Non-cash interest expense		165			191
Equity earnings, net of distributions received		(233	)		(330	)
Changes in operating assets and liabilities		(4,398	)		(6,655	)
Net cash provided by operating activities		23,518			13,317
Cash flows from investing activities
Acquisitions, net of cash acquired		(339	)		(3,069	)
Additions to property, plant and equipment		(7,002	)		(5,496	)
Other		43			—
Net cash used in investing activities		(7,298	)		(8,565	)
Cash flows from financing activities
Distributions to partners		(21,029	)		(15,524	)
Proceeds from borrowings		10,000			—
Repayments of borrowings		(5,000	)		(3,300	)
Proceeds from issuance of Class B units		860			—
Net cash used in financing activities		(15,169	)		(18,824	)
Net increase (decrease) in cash and cash equivalents		1,051			(14,072	)
Cash and cash equivalents – beginning of period		11,440			23,193
Cash and cash equivalents – end of period	$	12,491		$	9,121
Supplemental disclosure:
Cash paid for interest	$	4,534		$	5,352

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

March 31, 2007

1. Organization

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “us” or “our”) is a Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 primarily to engage in the business of managing coal properties in the United States. We conduct operations in two business segments: coal and natural gas midstream.

In our coal segment, we do not operate any mines. Instead, we enter into leases with various third-party operators which give those operators the right to mine coal reserves on our land in exchange for royalty payments. We also provide fee-based infrastructure facilities to some of our lessees and third parties to generate coal services revenues. These facilities include coal loading facilities, preparation plants and coal handling facilities located at end-user industrial plants. We also sell timber growing on our land.

In our natural gas midstream segment, we own and operate a significant set of midstream assets. 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.

Our general partner is Penn Virginia Resource GP, LLC (“PVG”), which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. 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 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, 2006. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

The condensed consolidated financial statements include the accounts of the Partnership and all wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. The 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 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 the condensed consolidated financial statements have been included. These financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2006. Operating results for the three months ended March 31, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. Certain reclassifications have been made to conform to the current period’s presentation.

New Accounting Standards

In February 2007, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standard (“SFAS”) No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We have not yet determined the impact on our financial statements of adopting SFAS No. 159 effective January 1, 2008.

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3. Equity Investments

In July 2004, we acquired from affiliates of Massey Energy Company (“Massey”) a 50% interest in Coal Handling Solutions, LLC, a joint venture formed to own and operate end-user coal handling facilities. We account for the investment under the equity method of accounting. In 2004, the original cash investment of $28.4 million was capitalized. At March 31, 2007, our equity investment totaled $25.5 million, which exceeded our portion of the underlying equity in net assets by $8.2 million. The difference is being amortized to equity earnings over the life of coal services contracts in place at the time of the acquisition. In accordance with the equity method, we recognized equity earnings in the three months ended March 31, 2007 and 2006 of $0.2 million and $0.3 million, with a corresponding increase in the investment. The joint venture generally pays to us quarterly distributions of our portion of the joint venture’s operating cash flows. We received no cash distributions from the joint venture in the three months ended March 31, 2007 or 2006. Equity earnings are included in coal services revenues on our condensed consolidated statements of income.

4. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of gas purchased. 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 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.

The fair values of our derivative agreements are determined based on forward price quotes and regression analysis for the respective commodities as of March 31, 2007. The following table sets forth our positions as of March 31, 2007 for commodities related to natural gas midstream revenues (ethane, propane and crude oil) and cost of midstream gas purchased (natural gas):

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	Average Volume Per Day		Weighted Average Price			Estimated Fair Value (in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	34,440		$	0.5050		$	(1,489	)
First Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700			(1,950	)
Propane Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	26,040		$	0.7550			(2,395	)
First Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175			(3,054	)
Natural Gasoline Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	23,520		$	1.2650			(2,040	)
Crude Oil Swaps	(in barrels	)		(per barrel	)
Second Quarter 2007 through Fourth Quarter 2007	560		$	50.80			(2,706	)
First Quarter 2008 through Fourth Quarter 2008	560		$	49.27			(3,966	)
Crude Oil Swaps (purchase)	(in barrels	)		(per barrel	)
Second Quarter 2007 through Fourth Quarter 2007	560		$	57.12			1,755
Natural Gas Swaps	(in MMbtu	)		(per MMbtu	)
Second Quarter 2007 through Fourth Quarter 2008	4,000		$	6.97			3,754
March 2007 Settlements							(630	)
Natural gas midstream segment commodity derivatives—net liability						$	(12,721	)

Based upon our assessment of derivative agreements at March 31, 2007, we reported (i) a net derivative liability related to the natural gas midstream segment of $12.7 million, (ii) a loss in accumulated other comprehensive income of $9.2 million related to derivatives in the natural gas midstream segment for which we discontinued cash flow hedge accounting in 2006. The following table summarizes the effects of commodity derivative activities on our condensed consolidated statements of income:

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Income statement caption:
Midstream revenue	$	(2,286	)	$	(2,168	)
Cost of gas purchased		1,443			2,429
Derivatives		(2,647	)		(6,133	)
Increase (decrease) in net income	$	(3,490	)	$	(5,872	)
Realized and unrealized derivative impact:
Cash paid for derivative settlements	$	(2,072	)	$	(2,922	)
Unrealized derivative gain (loss)		(1,418	)		(2,950	)
Increase (decrease) in net income	$	(3,490	)	$	(5,872	)

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Interest Rate Swaps

In September 2005, we entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on $60 million of the portion of the outstanding balance on our revolving credit facility that is based on the London Inter Bank Offering Rate (“LIBOR”) until March 2010. We pay a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were 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 expense. We reported (i) a derivative asset of approximately $1.1 million at March 31, 2007 and (ii) a gain in accumulated other comprehensive income of $1.1 million at March 31, 2007 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.2 million in net hedging gains in interest expense for the year ended March 31, 2007.

5. Partners’ Capital and Distributions

As of March 31, 2007, partners’ capital consisted of 42.1 million common units, representing a 89% limited partner interest, 4.0 million Class B units, representing a 9% limited partner interest, and a 2% general partner interest. As of March 31, 2007, affiliates of Penn Virginia owned, in the aggregate, a 44% interest in us, consisting of 15.9 million common units, 4.0 million Class B units and a 2% general partner interest.

Net Income per Limited Partner Unit

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.

Cash Distributions

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 established by our general partner at its sole discretion. According to our partnership agreement, the 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	%

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The following table reflects the allocation of total cash distributions paid during the three months ended March 31, 2007 and 2006:

	Three Months Ended March 31,
	2007		2006
	(in thousands, except per unit information)
Limited partner units	$	18,443	$	14,576
General partner interest (2%)		376		297
Incentive distribution rights		2,210		651
Total cash distributions paid	$	21,029	$	15,524
Total cash distributions paid per unit	$	0.40	$	0.35

We paid a quarterly distribution of $0.40 per unit in February 2007. In April 2007, we announced a $0.41 per unit distribution for the three months ended March 31, 2007, or $1.64 per unit on an annualized basis. The distribution will be paid on May 15, 2007 to unitholders of record at the close of business on May 4, 2007.

6. Related Party Transactions

Sale of Units to PVG

We sold 33,147 newly issued Class B units to PVG in January 2007 for $25.45 per Class B unit, which was the same price as the Class B units we sold to PVG in December 2006. PVG paid us an aggregate of $0.9 million for the purchase of the Class B units and to maintain its 2% general partner interest in us.

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 $1.1 million and $1.6 million for the three months ended March 31, 2007 and 2006. These costs are reflected in general and administrative expenses in our condensed consolidated statements of income. At least annually, management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, management believes the allocation methodologies used are reasonable.

Accounts Payable—Affiliate

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

Marketing Revenues

Connect Energy Services, LLC, a wholly-owned subsidiary of the Partnership, earned $0.4 million in fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during the three months ended March 31, 2007. The marketing agreement was effective September 1, 2006. Penn Virginia Oil & Gas, L.P. is a wholly-owned subsidiary of Penn Virginia. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

7. Long-Term Incentive Plan

For the three months ended March 31, 2007 and 2006, we recognized a total of $0.5 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, 2007, 85,233 restricted units with a weighted average grant date fair value of $26.85 per unit were granted to employees of Penn Virginia. During the same period, 42,582 restricted units with a weighted average grant date fair value $27.56 per unit vested. Restricted units granted in 2007 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.

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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. For the three months ended March 31, 2007 and 2006, the components of comprehensive income were as follows:

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Net income	$	16,433		$	8,340
Unrealized holding losses on derivative activities		(200	)		(1,966	)
Reclassification adjustment for derivative activities		672			160
Comprehensive income	$	16,905		$	6,534

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, management believes these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

The operations of our coal lessees and our natural gas midstream segment 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 coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of our coal lessees and our natural gas midstream segment comply with existing regulations and does not expect any material impact on our financial condition or results of operations.

As of March 31, 2007, environmental liabilities included $1.6 million, which represents our best estimate of our liabilities as of that date related to our coal 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 chief operating decision-making group consists of the Chief Executive Officer and other senior officers.

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This group routinely reviews and makes operating and resource allocation decisions among our coal operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:

• Coal – 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.

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

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

	Coal		Natural Gas Midstream		Consolidated
			(in thousands)
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
Additions to property and equipment and acquisitions	$	1,336	$	6,005	$	7,341
For the Three Months Ended March 31, 2006:
Revenues	$	25,328	$	109,836	$	135,164
Cost of midstream gas purchased		—		98,651		98,651
Operating costs and expenses		3,509		5,937		9,446
Depreciation, depletion and amortization		4,752		4,069		8,821
Operating income	$	17,067	$	1,179		18,246
Interest expense, net						(3,773	)
Derivatives						(6,133	)
Net income					$	8,340
Additions to property and equipment and acquisitions	$	6,004	$	2,561	$	8,565

11. Subsequent Events

Subsequent to March 31, 2007, we entered into five commodity derivative agreements. Four of the derivative agreements are costless collar contracts utilized to mitigate commodity price exposure related to our percent-of-proceeds contracts. The following table summarizes the terms of these positions:

	Volume Per Day	Floor Price		Ceiling Price
	(in gallons)	(per gallon)		(per gallon)
Ethane Costless Collar
May 2007 through December 2007	5,000	$	0.6100	$	0.7125
Propane Costless Collar
May 2007 through December 2007	9,000	$	1.0300	$	1.1640
Natural Gasoline Costless Collar
May 2007 through December 2007	6,300	$	1.4800	$	1.6465
	(in barrels)	(per barrel)		(per barrel)
Crude Oil Costless Collar
May 2007 through December 2007	400	$	65.00	$	75.25

The fifth commodity derivative agreement entered into subsequent to March 31, 2007 is a swap derivative contract utilized to mitigate frac spread exposure related to our wellhead purchase contracts. This derivative contract consists of an agreement to sell natural gas liquids forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. The following table summarizes the terms of the contract:

Frac Spread Swap
June 2007 through December 2007
	Volume Per Day	Swap Price
	(in gallons)	(per gallon)
Ethane	36,719	$	0.7150
Propane	27,029	$	1.1600
Isobutane	3,825	$	1.3725
Normal Butane	9,095	$	1.3425
Natural Gasoline	8,330	$	1.6300
	(in mmbtu)	(per mmbtu)
Natural Gas (1)	7,128	$	7.8850

(1) Priced at Northern Natural Gas Co. Demarcation Index.

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

The following review of the financial condition and results of operations of Penn Virginia Resource Partners, L.P. (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.” Our discussion and analysis include the following items:

• Overview of Business

• Current Performance

• Summary of Critical Accounting Policies and Estimates

• Liquidity and Capital Resources

• Results of Operations

• Environmental Matters

• Recent Accounting Pronouncements

• Forward-Looking Statements

Overview of Business

We are a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 that is principally engaged in the management of coal 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: coal and natural gas midstream. In the three months ended March 31, 2007, approximately 80%, or $17.9 million, of our operating income was attributable to our coal segment, and approximately 20%, or $4.4 million, of our operating income was attributable to our natural gas midstream segment.

Coal Segment

As of December 31, 2006, we owned or controlled approximately 765 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 do not operate any mines. In the three months ended March 31, 2007, our lessees produced 8.3 million tons of coal from our properties and paid us coal royalty revenues of $25.0 million, for an average gross coal royalty per ton of $3.02. Approximately 81% of our coal royalty revenues in the three months ended March 31, 2007 and 2006 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 royalty 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. The possibility exists that new legislation or regulations have 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.

Coal prices also impact coal royalty revenues. Coal prices, especially in Central Appalachia where the majority of our coal is produced, increased significantly from the beginning of 2004 through most of 2006. The price increase during that period was primarily the result of increased electricity demand, rebuilding of inventories and decreasing coal production in Central Appalachia. In the second half of 2006 and continuing into 2007, coal prices decreased from the historically high levels experienced in the previous two and one half years, due to higher than normal coal inventories at electric utilities and milder than normal winter weather.

Substantially all of our leases require the lessee to pay minimum rental payments to us in monthly or annual installments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We also earn revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their

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production levels and generate additional coal royalty revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through our joint venture with Massey. In addition, we earn revenues from oil and gas royalty interests we own, from coal transportation rights and from the sale of standing timber on our properties.

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

Natural Gas Midstream Segment

We own and operate midstream assets that include approximately 3,631 miles of natural gas gathering pipelines and three natural gas processing facilities located in Oklahoma and the panhandle of Texas, which have 160 million cubic feet per day (“MMcfd”) of total capacity. Our 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. We acquired our natural gas midstream assets through the acquisition of Cantera Gas Resources, LLC in March 2005. We believe that this acquisition established a platform for future growth in the natural gas midstream sector and diversified our cash flows into another long-lived asset base. Since acquiring these assets, we have expanded our natural gas midstream business by adding 181 miles of new gathering lines.

For the three months ended March 31, 2007, throughput volumes at our gas processing plants and gathering systems were 15.9 billion cubic feet (“Bcf”), or approximately 177 MMcfd, and three of our natural gas midstream customers accounted for 56% of our natural gas midstream revenues.

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 throughput volume. 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 by contracting for natural gas that has been released from competitors’ systems.

Revenues, profitability and the future rate of growth of the natural gas midstream segment are highly dependent on market demand and prevailing natural gas liquid (“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.

Current Performance

Operating income for the three months ended March 31, 2007 was $22.3 million, compared with $18.2 million for the three months ended March 31, 2006. The coal segment contributed $17.9 million, or 80%, to operating income, and the natural gas midstream segment contributed $4.4 million, or 20%. The following table presents a summary of certain financial information relating to our segments:

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	Coal		Natural Gas Midstream		Consolidated
	(in thousands)
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
For the Three Months Ended March 31, 2006:
Revenues	$	25,328	$	109,836	$	135,164
Cost of midstream gas purchased		—		98,651		98,651
Operating costs and expenses		3,509		5,937		9,446
Depreciation, depletion and amortization		4,752		4,069		8,821
Operating income	$	17,067	$	1,179	$	18,246

Coal Segment

In the three months ended March 31, 2007, coal royalty revenues increased 11%, or $2.6 million, over the same time period in 2006 due to acquisitions and an increase in production by our lessees. Tons produced by our lessees increased from 7.7 million tons in the three months ended March 31, 2006 to 8.3 million tons in the same period of 2007, and our average gross royalties per ton increased from $2.90 in the three months ended March 31, 2006 to $3.02 in the same period in 2007. Generally, as coal prices change, our average royalties per ton also change 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 royalties occur as our lessees’ contracts are renegotiated. The coal reserves in West Virginia that we acquired in May 2006 resulted in $1.5 million of coal royalty revenues in the three months ended March 31, 2007.

Coal services revenues increased to $1.6 million in the three months ended March 31, 2007 from $1.4 million in the same period of 2006. This increase was due primarily to the completed construction of a coal service facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.4 million to coal services revenues in the three months ended March 31, 2007. We believe that these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

The following table summarizes coal production and coal royalty revenues by property:

	Coal Production		Coal Royalty Revenues
Property	Three Months Ended March 31		Three Months Ended March 31
	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	4,957	4,398	$	18,910	$	16,667
Northern Appalachia	1,370	1,283		2,103		1,868
Illinois Basin	619	717		1,307		1,401
San Juan Basin	1,338	1,322		2,680		2,486
Total	8,284	7,720	$	25,000	$	22,422

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Natural Gas Midstream Segment

The gross processing margin for our natural gas midstream operations increased from $10.5 million in the three months ended March 31, 2006 to $15.6 million in the three months ended March 31, 2007. This increase was due primarily to a stronger pricing environment for the first quarter of 2007 compared to the first quarter of 2006 with higher fractional spreads for the period. System throughput volumes at our gas processing plants and gathering systems were 177 MMcfd for the three months ended March 31, 2007, an increase of 19 MMcfd from the three months ended March 31, 2006, primarily due to higher average daily system throughput volumes resulting from the pipeline acquisition completed in the second quarter of 2006 and successful drilling of local producers. Our midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the three months ended March 31, 2007, the natural gas midstream business generated a majority of its gross margin from contractual arrangements under which its 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. See the tables in Note 4 in the Notes to Condensed Consolidated Financial Statements for the effects of our derivative program on gross processing margin.

Our natural gas midstream assets are primarily located in the Mid-Continent area of Oklahoma and the panhandle of Texas. The following table sets forth information regarding our natural gas midstream assets as of March 31, 2007:

Asset	Type	Approximate Length (Miles)	Approximate Wells Connected	Current Processing Capacity (Mmcfd)	Three Months Ended March 31, 2007
					Average System Throughput (Mmcfd)	Utilization of Processing Capacity (%)
Beaver/Perryton System	Gathering pipelines and processing facility	1,377	934	100	136(1)	100.0	%
Crescent System	Gathering pipelines and processing facility	1,679	888	40	19	47.5	%
Hamlin System	Gathering pipelines and processing facility	497	231	20	9	45.0	%
Arkoma System	Gathering pipelines	78	78	—	13(2)
		3,631	2,131	160	177

(1) Includes gas processed at other systems connected to the Beaver/Perryton System via the pipeline acquired in June 2006.

(2) Gathering only volumes.

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.

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Natural Gas Midstream Revenues

Revenue from the sale of NGLs and residue gas is recognized when the NGLs and residue gas produced at our gas processing plants are sold. Gathering and transportation revenue is recognized 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, accruals for revenues and accounts receivable and the related cost of gas purchased and accounts payable are made based on estimates of natural gas purchased and NGLs and natural gas sold, and our financial results include estimates of production and revenues for the period of actual production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received or paid and the original estimates are recorded in the period they become finalized.

Coal Royalty Revenues

Coal royalty revenues are recognized 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. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

Derivative Activities

We historically have entered into derivative financial instruments that would qualify for hedge accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our condensed consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the hedged transaction settles. Because during the first quarter of 2006 our natural gas derivatives and a large portion of our NGL derivatives no longer qualified for hedge accounting and to increase clarity in our condensed consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses 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 could experience significant changes in the estimate of derivative gain or loss recognized in revenues and cost of midstream gas purchased due to swings in the value of these contracts. These fluctuations could be significant in a volatile pricing environment.

The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. This change in reporting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices.

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 outside consultants. Our estimates of coal reserves are updated annually and may result in adjustments to coal reserves and depletion rates that are recognized prospectively.

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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.

Intangibles

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.

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 revolving credit facility. 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 the natural gas midstream market, some of which are beyond our control.

Summarized cash flow statements for the three months ended March 31, 2007 and 2006, consolidating our segments, are set forth below (in thousands):

For the three-months ended March 31, 2007	Coal			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 decrease in cash and cash equivalents							$	1,051

For the three-months ended March 31, 2006	Coal			Natural Gas Midstream			Consolidated
Cash flows from operating activities:
Net income contribution	$	13,088		$	(4,748	)	$	8,340
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		4,613			7,019			11,632
Net change in operating assets and liabilities		(656	)		(5,999	)		(6,655	)
Net cash provided by (used in) operating activities	$	17,045		$	(3,728	)		13,317
Net cash used in investing activities	$	(6,170	)	$	(2,395	)		(8,565	)
Net cash (used in) financing activities								(18,824	)
Net increase in cash and cash equivalents							$	(14,072	)

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Cash Flows

Cash provided by operating activities increased $10.2 million, or 77%, to $23.5 million for the three months ended March 31, 2007 from $13.3 million for the three months ended March 31, 2006. The overall increase in cash provided by operating activities for the three months ended March 31, 2007 compared to the same period of 2006 was primarily attributable to an increase in coal royalty revenues and an overall increase in working capital.

Capital expenditures, excluding non-cash items, for the three months ended March 31, 2007 and 2006 were as follows:

	Three Months Ended March 31,
	2007		2006
	(in thousands)
Coal
Acquisitions (1)	$	339	$	2,689
Expansion capital expenditures		85		2,186
Other property and equipment expenditures		39		57
Total		463		4,932
Natural gas midstream
Expansion capital expenditures		5,677		1,963
Other property and equipment expenditures		1,907		598
Total		7,584		2,561
Total capital expenditures	$	8,047	$	7,493

Cash flows from operations funded our capital expenditures for the three months ended March 31, 2007 and 2006. Distributions to partners increased to $21.0 million in the three months ended March 31, 2007 from $15.5 million in the three months ended March 31, 2006 because we increased the quarterly unit distribution to $0.40 per unit from $0.35 per unit.

Long-Term Debt

As of March 31, 2007, we had outstanding borrowings of $223.1 million, consisting of $153.2 million borrowed under our revolving credit facility and $69.9 million of senior unsecured notes (the “Notes”). The current portion of the Notes as of March 31, 2007 was $11.8 million.

Revolving Credit Facility. As of March 31, 2007, we had $153.2 million outstanding under our $300 million unsecured revolving credit facility (the “Revolver”) that matures in December 2011. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $1.6 million as of March 31, 2007. In the three months ended March 31, 2007, we incurred commitment fees of $0.1 million on the unused portion of the Revolver. We have a one-time option to expand the Revolver by $150 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders. The interest rate under the Revolver fluctuates based on our ratio of 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 the London Inter Bank Offering Rate (“LIBOR”) plus an applicable margin ranging from 0.75% to 1.75% if we select the LIBOR-based borrowing option.

The financial covenants under the Revolver require us to maintain specified levels of debt to consolidated EBITDA and consolidated EBITDA to interest. The financial covenants restricted our borrowing capacity under the Revolver to approximately $273.8 million as of March 31, 2007. At the current $300 million limit on the Revolver, and given our outstanding balance of $153.2 million, net of $1.6 million of letters of credit, we could borrow up to $145.2 million without exercising our one-time option to

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expand the Revolver. In order to utilize the full extent of the $273.8 million borrowing capacity, we would need to exercise our one-time option to expand the Revolver by $150 million. 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, 2007, we were in compliance with all of our covenants under the Revolver.

Senior Unsecured Notes. As of March 31, 2007, we owed $69.9 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 2007, 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, 2007, we were in compliance with all of our covenants under the Notes.

Interest Rate Swaps. In September 2005, we entered into interest rate swap agreements (“the Revolver Swaps”) with notional amounts totaling $60 million to establish fixed rates on the LIBOR-based portion of the outstanding balance of the Revolver until March 2010. We pay a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were 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 0.75% in effect as March 31, 2007, the total interest rate on the $60 million portion of Revolver borrowings covered by the Revolver Swaps was 4.97% at March 31, 2007.

Future Capital Needs and Commitments

Part of our strategy is to make acquisitions which increase cash available for distribution to our unitholders. 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. 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 at the time.

In 2007, we anticipate making capital expenditures, excluding acquisitions, of $3.6 million to $4.7 million for coal services related projects and other property and equipment and $50 to $54 million for natural gas midstream system expansion projects. We intend to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the Revolver, under which we had $145.2 million of borrowing capacity as of March 31, 2007. 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. Funding sources for future acquisitions are dependent on the size of any such acquisitions and are expected to be provided by a combination of cash flows provided by operating activities and borrowings, and potentially with the proceeds from the issuance of additional equity.

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.

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Results of Operations

The following table sets for a summary of certain financial data for the periods indicated:

Selected Financial Data – Consolidated

	Three Months Ended March 31,
	2007		2006
	(in thousands, except per unit data)
Revenues	$	124,200	$	135,164
Expenses	$	101,860	$	116,918
Operating income	$	22,340	$	18,246
Net income	$	16,433	$	8,340
Net income per limited partner unit, basic and diluted	$	0.30	$	0.19
Cash flows provided by operating activities	$	23,518	$	13,317

The increase in net income for the three months ended March 31, 2007 compared to the same period in 2006 was primarily attributable to a $4.1 million increase in operating income, a $3.5 million decrease in derivative losses and a decrease of $0.5 million in interest expense as a result of making a $114.6 million principal payment on our Revolver in December 2006. Operating income increased for the three months ended March 31, 2007 primarily due to a stronger pricing environment and higher system throughput volumes in the natural gas midstream segment, as well as increased coal royalty revenues resulting from higher average royalty prices per ton and production from our lessees.

Coal Segment

The following table sets forth a summary of certain financial and other data for our coal segment and the percentage change for the periods indicated:

	Three Months Ended March 31,				% Change
	2007		2006
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	25,000	$	22,422	11	%
Coal services		1,601		1,426	12	%
Other		1,883		1,480	27	%
Total revenues		28,484		25,328	12	%
Expenses
Operating		2,155		969	122	%
Taxes other than income		323		310	4	%
General and administrative		2,616		2,230	17	%
Depreciation, depletion and amortization		5,490		4,752	16	%
Total expenses		10,584		8,261	28	%
Operating income	$	17,900	$	17,067	5	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,284		7,720	7	%
Average royalty per ton ($/ton)	$	3.02	$	2.90	4	%

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Revenues. Coal royalty revenues increased to $25.0 million for the three months ended March 31, 2007 from $22.4 million for the same period in 2006, or 11%, due to acquisitions and increased production by our lessees. Tons produced by our lessees increased from 7.7 million tons in the three months ended March 31, 2006 to 8.3 million tons in the same period of 2007, and our average gross royalties per ton increased from $2.90 for the three months ended March 31, 2006 to $3.02 for the same period in 2007. The increase in the average royalty per ton was primarily due to a greater percentage of coal being produced from certain price-sensitive leases and, for most of 2007, stronger market conditions for coal resulting in higher prices. Generally, as coal prices change, our average royalties per ton also change 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 royalties occur as our lessees’ contracts are renegotiated. The coal reserves in West Virginia that we acquired in May 2006 resulted in $1.5 million of coal royalty revenues in the three months ended March 31, 2007.

Coal services revenues increased to $1.6 million for the three months ended March 31, 2007 from $1.4 million for the same period in 2006, or 12%, primarily due to the completed construction of a coal service facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.4 million to coal service revenue in the three months ended March 31, 2007. We believe these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

Expenses. Operating expenses increased to $2.2 million for the three months ended March 31, 2007 from $1.0 million for the same period in 2006, or 122%, due to production on our subleased Central Appalachian property acquired in May 2006. Fluctuations in production on subleased properties have a direct impact on royalty expense. General and administrative expenses increased by 17% to $2.6 million due to increased payroll costs and professional fees related to evaluating acquisition opportunities. Depreciation, depletion and amortization expense increased by 16% to 5.5 million due to the increase in production and a higher depletion rate on recently acquired reserves.

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Natural Gas Midstream Segment

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 periods indicated:

	Three Months Ended March 31,				% Change
	2007		2006
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	59,680	$	78,530	(24	%)
Natural gas liquids		31,988		28,037	14	%
Condensate		2,916		2,272	28	%
Gathering and transportation fees		734		342	115	%
Total natural gas midstream revenues		95,318		109,181	(13	%)
Producer Services		398		655	(39	%)
Total revenues		95,716		109,836	(13	%)
Expenses
Cost of gas purchased		79,731		98,651	(19	%)
Operating		3,359		2,509	34	%
Taxes other than income		520		388	34	%
General and administrative		3,023		3,040	(1	%)
Depreciation and amortization		4,643		4,069	14	%
Total operating expenses		91,276		108,657	(16	%)
Operating income	$	4,440	$	1,179	277	%
Operating Statistics
Throughput volumes (MMcf)		15,900		14,200	12	%
Midstream processing margin	$	15,587	$	10,530	48	%

Revenues. 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, gathering and other fees primarily from natural gas volumes connected to our gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants. The decrease in natural gas midstream revenues was primarily a result of a decrease in prices for NGLs and condensate.

Expenses. Operating costs and expenses primarily consisted of the cost of gas purchased and also included operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization. The decrease in expenses was primarily due to a decrease in cost of gas purchased, which was partially offset by an increase in operating expenses.

Cost of gas purchased consisted of amounts payable to third-party producers for natural gas purchased under percentage of proceeds and keep-whole contracts. Cost of gas purchased was lower primarily due to a decrease in prices for NGLs and condensate, which lowered the cost of gas purchased. Included in cost of gas purchased for the three months ended March 31, 2006 was a $4.6 million non-cash charge to reserve for amounts related to balances assumed as part of the acquisition of our natural gas midstream business in 2005. The following table shows a summary of the effects of derivative activities on midstream processing margin:

	Three Months Ended March 31,
	2007			2006
	(in thousands)
Midstream processing margin, as reported	$	15,587		$	10,530
Derivatives (gains) losses included in midstream processing margin		843			(261	)
Midstream processing margin before impact of derivatives		16,430			10,269
Cash settlements on derivatives		(2,072	)		(2,922	)
Midstream processing margin, adjusted for derivatives	$	14,358		$	7,347

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Other

Interest Expense. Interest expense decreased by $0.6 million from $4.1 for the three months ended March 31, 2006 to $3.5 for the same period in 2007. This decrease was primarily due to making a $114.6 million payment on our Revolver in December 2006.

Derivatives. Derivative losses were $2.6 million and $6.1 million for the three months ended March 31, 2007 and 2006 for settlements and mark-to-market adjustments.

Environmental Matters

The operations of our coal lessees and our natural gas midstream segment 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 coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of our coal lessees and our natural gas midstream segment comply with existing regulations and does not expect any material impact on our financial condition or results of operations.

As of March 31, 2007, our environmental liabilities included $1.6 million, which represents our best estimate of the liabilities as of those dates related to our coal 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.

To dispose of mining overburden generated by their surface mining activities, our lessees need to obtain government approvals, including Federal Clean Water Act (“CWA”) Section 404 permits to construct valley fills and sediment control ponds. Two CWA Section 404 permits issued to Alex Energy, Inc. (“Alex Energy”), one of our surface coal mine lessees in West Virginia, were recently challenged in a lawsuit,Ohio Valley Environmental Coalition(“OVEC”) v. United States Army Corps of Engineers. On March 23, 2007, the U.S. District Court for the Southern District of West Virginia rescinded and remanded the permit authorizing several valley fills and sediment ponds that may be constructed at the Republic No. 2 Mine and enjoined Alex Energy from taking any further actions under this permit. The district court has yet to rule on whether the other CWA Section 404 permit for the construction of valley fills and associated sediment ponds at the Republic No. 1 Mine was also invalidly issued. Although portions of the Republic No. 2 Mine continue to operate based on a limited stay of the district court’s order pending appeal, construction of valley fills at other portions of the Republic No. 2 Mine are enjoined pending a final outcome of this litigation. While we are still reviewing the district court’s ruling, our lessees may not be able to obtain or may experience delays in securing additional CWA Section 404 permits for surface mining operations. Unless theOVEC decision is overturned or further limited in subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on our coal royalty revenues.

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 (the “Exchange Act”). 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 to our general partner and our unitholders;

• energy prices generally and specifically, the price of natural gas and the price of NGLs;

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• the relationship between natural gas and NGL prices;

• the price of coal and its comparison to the price of natural gas and oil;

• the volatility of commodity prices for coal, natural gas and NGLs;

• the projected demand for coal, natural gas and NGLs;

• the projected supply of coal, natural gas and NGLs;

• our ability to successfully manage our relatively new natural gas midstream business;

• our ability to acquire new coal reserves or midstream assets on satisfactory terms;

• the price for which coal reserves can be acquired;

• our ability to continually find and contract for new sources of natural gas supply;

• our ability to retain existing or acquire new midstream customers;

• our ability to lease new and existing coal reserves;

• the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves;

• the ability of our lessees to obtain favorable contracts for coal produced from our reserves;

• competition among producers in the coal industry generally and among natural gas midstream companies;

• our exposure to the credit risk of our coal lessees and midstream customers;

• the extent to which the amount and quality of our actual production differ from our estimated recoverable proved coal reserves;

• hazards or operating risks incidental to midstream operations;

• unanticipated geological problems;

• the dependence of our midstream business on having connections to third party pipelines;

• the availability of required materials and equipment;

• the occurrence of unusual weather or operating conditions including force majeure events;

• the failure of our infrastructure and our lessees’ mining equipment or processes to operate in accordance with specifications or expectations;

• delays in anticipated start-up dates of our 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 lessees;

• the risks associated with having or not having price risk management programs;

• labor relations and costs;

• accidents;

• changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators;

• uncertainties relating to the outcome of current and future litigation regarding mine permitting;

• risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions (including the impact of potential terrorist attacks);

• the experience and financial condition of our lessees, including their ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;

• our ability to expand our midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner;

• coal handling joint venture operations;

• changes in financial market conditions; and

• other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2006.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2006. 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.

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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 NGL, crude oil, natural gas 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 operating 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 value of our price risk management assets is significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

For the three months ended March 31, 2007, we reported a net $2.6 million derivative loss for settlements and mark-to-market adjustments. Because during the first quarter of 2006 our natural gas derivatives and a large portion of our NGL derivatives no longer qualified for hedge accounting and to increase clarity in our condensed consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices. See the discussion and tables in Note 4 in the Notes to Condensed Consolidated Financial Statements for a description of our derivative program. The following table lists our open mark-to-market derivative agreements and their fair values as of March 31, 2007:

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	Average Volume Per Day		Weighted Average Price			Estimated Fair Value (in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	34,440		$	0.5050			(1,489	)
First Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700			(1,950	)
Propane Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	26,040		$	0.7550			(2,395	)
First Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175			(3,054	)
Natural Gasoline Swaps	(in gallons	)		(per gallon	)
Second Quarter 2007 through Fourth Quarter 2007	23,520		$	1.2650			(2,040	)
Crude Oil Swaps	(in barrels	)		(per barrel	)
Second Quarter 2007 through Fourth Quarter 2007	560		$	50.80			(2,706	)
First Quarter 2008 through Fourth Quarter 2008	560		$	49.27			(3,966	)
Crude Oil Swaps (purchase)	(in barrels	)		(per barrel	)
Second Quarter 2007 through Fourth Quarter 2007	560		$	57.12			1,755
Natural Gas Swaps	(in MMbtu	)		(per MMbtu	)
Second Quarter 2007 through Fourth Quarter 2008	4,000		$	6.97			3,754
March 2007 Settlements							(630	)
Natural gas midstream segment commodity derivatives—net liability						$	(12,721	)

Subsequent to March 31, 2007, we entered into five commodity derivative agreements. Four of the derivative agreements are costless collar contracts utilized to mitigate commodity price exposure related to our percent-of-proceeds contracts. The following table summarizes the terms of these positions:

	Volume Per Day	Floor Price		Ceiling Price
	(in gallons)	(per gallon)		(per gallon)
Ethane Costless Collar
May 2007 through December 2007	5,000	$	0.6100	$	0.7125
Propane Costless Collar
May 2007 through December 2007	9,000	$	1.0300	$	1.1640
Natural Gasoline Costless Collar
May 2007 through December 2007	6,300	$	1.4800	$	1.6465
	(in barrels)	(per barrel)		(per barrel)
Crude Oil Costless Collar
May 2007 through December 2007	400	$	65.00	$	75.25

The fifth commodity derivative agreement entered into subsequent to March 31, 2007 is a swap derivative contract utilized to mitigate frac spread exposure related to our wellhead purchase contracts. This derivative contract consists of an agreement to sell natural gas liquids forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. The following table summarizes the terms of the contract:

Frac Spread Swap
June 2007 through December 2007
	Volume Per Day	Swap Price
	(in gallons)	(per gallon)
Ethane	36,719	$	0.7150
Propane	27,029	$	1.1600
Isobutane	3,825	$	1.3725
Normal Butane	9,095	$	1.3425
Natural Gasoline	8,330	$	1.6300
	(in mmbtu)	(per mmbtu)
Natural Gas (1)	7,128	$	7.8850

(1) Priced at Northern Natural Gas Co. Demarcation Index.

Interest Rate Risk

As of March 31, 2007, we had $153.2 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps in September 2005 to effectively convert the interest rate on $60 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.22% 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, 2007 would cost us approximately $0.9 million in additional interest expense.

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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, 2007. 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, 2007, 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 during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Items 1, 1A, 2, 3, 4 and 5 are not applicable and have been omitted.

Item 6 Exhibits

12.1	Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.
31.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification Pursuant to 18 U.S.C. Section 1350, 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.

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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 4, 2007	By:	/s/ Frank A. Pici
			Frank A. Pici
			Vice President and Chief Financial Officer
Date:	May 4, 2007	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller

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