Unassociated Document

10-Q 1 v183346_10q.htm FORM 10-Q Unassociated Document

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, 2010

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

For the transition period from

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.)

FOUR RADNOR CORPORATE CENTER, SUITE 200 100 MATSONFORD ROAD RADNOR, PA 19087
(Address of principal executive offices)	(Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

THREE RADNOR CORPORATE CENTER, SUITE 300

100 MATSONFORD ROAD

RADNOR, PA 19087

(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 (“Exchange Act”) 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 check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

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 the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ¨ Accelerated filer x

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 5, 2010, 51,893,291 common units representing limited partner interests 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, 2010 and 2009	1

	Condensed Consolidated Balance Sheets as of March 31, 2010 and December 31, 2009	2

	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2010 and 2009	3

	Notes to Condensed Consolidated Financial Statements	4

	Forward-Looking Statements	17

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Overview of Business	17
	Liquidity and Capital Resources	18
	Results of Operations	24
	Environmental Matters	30
	Critical Accounting Estimates	31
	New Accounting Standards	31

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 4.	Controls and Procedures	35

PART II.	Other Information

Item 1A.	Risk Factors	36

Item 6.	Exhibits	39

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)

	Three Months Ended
	March 31,
	2010			2009
Revenues
Natural gas midstream	$	170,609		$	117,379
Coal royalties		28,226			30,630
Coal services		1,973			1,888
Other		5,670			6,862
Total revenues		206,478			156,759

Expenses
Cost of midstream gas purchased		141,795			100,620
Operating		9,263			8,890
Taxes other than income		1,518			1,223
General and administrative		8,338			7,596
Depreciation, depletion and amortization		17,818			16,503
Total expenses		178,732			134,832

Operating income		27,746			21,927

Other income (expense)
Interest expense		(5,835	)		(5,616	)
Other		308			318
Derivatives		(7,568	)		(7,161	)

Net income	$	14,651		$	9,468

General partner’s interest in net income	$	6,218		$	6,104

Limited partners’ interest in net income	$	8,433		$	3,364

Basic and diluted net income per limited partner unit (see Note 6)	$	0.16		$	0.06

Weighted average number of units outstanding, basic and diluted		51,846			51,799

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)

	March 31,			December 31,
	2010			2009
Assets
Current assets
Cash and cash equivalents	$	17,527		$	8,659
Accounts receivable, net of allowance for doubtful accounts		72,801			82,321
Derivative assets		1,320			1,331
Other current assets		4,419			4,468
Total current assets		96,067			96,779

Property, plant and equipment		1,171,250			1,162,070
Accumulated depreciation, depletion and amortization		(277,306	)		(261,226	)
Net property, plant and equipment		893,944			900,844

Equity investments		87,159			87,601
Intangible assets, net		82,043			83,741
Derivative assets		283			1,284
Other long-term assets		36,512			37,811

Total assets	$	1,196,008		$	1,208,060

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	62,147		$	60,679
Accrued liabilities		8,488			9,726
Deferred income		4,439			3,839
Derivative liabilities		14,975			11,251
Total current liabilities		90,049			85,495

Deferred income		4,843			5,482
Other liabilities		15,890			16,191
Derivative liabilities		5,469			4,285
Long-term debt		618,100			620,100

Partners’ capital		461,657			476,507

Total liabilities and partners’ capital	$	1,196,008		$	1,208,060

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended
	March 31,
	2010			2009

Cash flows from operating activities
Net income	$	14,651		$	9,468
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,818			16,503
Commodity derivative contracts:
Total derivative losses		8,150			7,615
Cash settlements of derivatives		(1,646	)		2,836
Non-cash interest expense		1,243			491
Equity earnings, net of distributions received		443			(1,559	)
Other		635			(295	)
Changes in operating assets and liabilities:
Accounts receivable		9,504			16,059
Accounts payable		(3,978	)		(13,805	)
Accrued liabilities		(956	)		(1,129	)
Deferred income		(39	)		(1,560	)
Other asset and liabilities		3,777			(251	)
Net cash provided by operating activities		49,602			34,373

Cash flows from investing activities
Acquisitions		(29	)		(1,256	)
Additions to property, plant and equipment		(7,957	)		(17,050	)
Other		272			265
Net cash used in investing activities		(7,714	)		(18,041	)

Cash flows from financing activities
Distributions to partners		(31,042	)		(30,877	)
Proceeds from borrowings		10,000			27,000
Repayments of borrowings		(12,000	)		-
Net proceeds from issuance of partners’ capital		22			-
Debt issuance costs		-			(9,258	)
Net cash used in financing activities		(33,020	)		(13,135	)

Net increase in cash and cash equivalents		8,868			3,197
Cash and cash equivalents – beginning of period		8,659			9,484
Cash and cash equivalents – end of period	$	17,527		$	12,681

Supplemental disclosure:
Cash paid for interest	$	6,429		$	6,156

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, 2010

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: (i) coal and natural resource management and (ii) 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. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn revenues from other land management activities, such as selling standing timber, 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 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. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. Wee also own a 50% percent member interest in Crosspoint Pipeline LLC (“Crosspoint”), a joint venture that gathers and transports natural gas from our Crossroads gas processing plant to an interstate pipeline. 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. At March 31, 2010, Penn Virginia owned an approximately 26% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At March 31, 2010, PVG owned an approximately 37% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us.

2. Basis of Presentation

Our condensed consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Investments in non-controlled entities over which we exercise significant influence are accounted for using the equity method. 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. 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. Our condensed consolidated 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, 2009. Operating results for the three months ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

Management has evaluated all activities of the Partnership through the date upon which the Condensed Consolidated Financial Statements were issued, and concluded that no subsequent events have occurred that would require recognition in the Condensed Consolidated Financial Statements, but disclosure is required in the Notes to the Condensed Consolidated Financial Statements. See Note 13 to the Condensed Consolidated Financial Statements.

All dollar amounts presented in the tables to these Notes are in thousands unless otherwise indicated.

3. Fair Value Measurements

We apply the authoritative accounting provisions for measuring fair value of both our financial and nonfinancial assets and liabilities. Fair value is an exit price representing the expected amount we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We have followed consistent methods and assumptions to estimate the fair values as more fully described in our Annual Report on Form 10-K for the year ended December 31, 2009.

Our financial instruments that are subject to fair value disclosure consist of cash and cash equivalents, accounts receivable, accounts payable, derivatives and long-term debt. At March 31, 2010, the carrying values of all of these financial instruments approximated fair value. The fair value of floating-rate debt approximates the carrying amount because the interest rates paid are based on short-term maturities.

Recurring Fair Value Measurements

Certain assets and liabilities, including our derivatives, are measured at fair value on a recurring basis in our Condensed Consolidated Balance Sheet. The following tables summarize the valuation of our assets and liabilities for the periods presented:

				Fair Value Measurements at March 31, 2010, Using
Description	Fair Value Measurements at March 31, 2010			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap assets - noncurrent	$	186		$	-	$	186		$	-
Interest rate swap liabilities - current		(7,445	)		-		(7,445	)		-
Interest rate swap liabilities - noncurrent		(3,128	)		-		(3,128	)		-
Commodity derivative assets - current		1,320			-		1,320			-
Commodity derivative assets - noncurrent		97			-		97			-
Commodity derivative liabilities - current		(7,530	)		-		(7,530	)		-
Commodity derivative liabilities - noncurrent		(2,341	)		-		(2,341	)		-
Total	$	(18,841	)	$	-	$	(18,841	)	$	-

				Fair Value Measurements at December 31, 2009, Using
Description	Fair Value Measurements at December 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap assets - noncurrent	$	1,266		$	-	$	1,266		$	-
Interest rate swap liabilities - current		(7,710	)		-		(7,710	)		-
Interest rate swap liabilities - noncurrent		(3,241	)		-		(3,241	)		-
Commodity derivative assets - current		1,331			-		1,331			-
Commodity derivative assets - noncurrent		18			-		18			-
Commodity derivative liabilities - current		(3,541	)		-		(3,541	)		-
Commodity derivative liabilities - noncurrent		(1,044	)		-		(1,044	)		-
Total	$	(12,921	)	$	-	$	(12,921	)	$	-

We used the following methods and assumptions to estimate the fair values:

•

Commodity derivatives : We utilize collar derivative contracts to hedge against the variability in the frac spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. Each of these is a level 2 input. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 4 for the effects of the derivative instruments on our Condensed Consolidated Statements of Income.

•

Interest rate swaps: We have entered into the interest rate swaps (“Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the revolving credit facility (“Revolver”). We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the

fair value of the swaps based on published interest rate yield curves as of the date of the estimate. Each of these is a level 2 input.

4. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We determine the fair values of our derivative agreements using third-party quoted forward prices for the respective commodities as of the end of the reporting period and discount rates adjusted for the credit risk of our counterparties if the derivative is in an asset position and our own credit risk if the derivative is in a liability position. The following table sets forth our commodity derivative positions as of March 31, 2010:

	Average								Fair Value at
	Volume Per				Weighted Average Price				March 31,
	Day		Swap Price		Put		Call		2010

Crude Oil Collar	(barrels)				($ per barrel)
Second Quarter 2010 through Fourth Quarter 2010		1,750			$	68.86	$	80.54	$	(3,309	)
First Quarter 2011 through Fourth Quarter 2011		400			$	75.00	$	98.50	$	35

Natural Gas Purchase Swap	(MMBtu)		($ per MMBtu)
Second Quarter 2010 through Fourth Quarter 2010		7,100	$	5.885					$	(3,133	)
First Quarter 2011 through Fourth Quarter 2011		6,500	$	5.796					$	(1,043	)

Ethane Swap	(gallons)		($ per gallon)
Second Quarter 2010		72,000	$	0.735					$	1,062

NGL - Natural Gasoline Collar	(gallons)				($ per gallon)
Third Quarter 2010 through Fourth Quarter 2010		42,000			$	1.55	$	2.03	$	(212	)
First Quarter 2011 through Fourth Quarter 2011		95,000			$	1.57	$	1.94	$	(2,025	)

Settlements to be received in subsequent period									$	171

Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the positions of the Interest Rate Swaps for the periods presented:

	Notional Amounts		Swap Interest Rates (1)				Fair Value
Term	(in millions)		Pay			Receive	March 31, 2010			December 31, 2009
Until March 2010	$	310.0		3.54	%	LIBOR	$	-		$	(2,479	)
March 2010 - December 2011	$	250.0		3.37	%	LIBOR	$	(10,999	)	$	(8,456	)
December 2011 - December 2012	$	100.0		2.09	%	LIBOR	$	612		$	1,252

(1)

References to LIBOR represent the 3-month rate.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the Derivatives caption on our Condensed Consolidated Statements of Income. As of March 31, 2010, a $0.8 million loss remained in accumulated other comprehensive income (“AOCI”) related to the Interest Rate Swaps. The $0.8 million loss will be recognized in interest expense when the original forecasted transactions occur.

We reported a (i) net derivative liability of $10.4 million at March 31, 2010 and (ii) loss in AOCI of $0.8 million as of March 31, 2010 related to the Interest Rate Swaps. In connection with periodic settlements, we reclassified a total of $0.6 million of net hedging losses on the Interest Rate Swaps from AOCI to interest expense during the three months ended March 31, 2010. See the “Financial Statement Impact of Derivatives” section below for the impact of the Interest Rate Swaps on our Condensed Consolidated Financial Statements.

Financial Statement Impact of Derivatives

The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our Condensed Consolidated Statements of Income for the periods presented:

	Location of gain (loss)
	on derivatives recognized	Three Months Ended March 31,
	in income	2010			2009
Derivatives not designated as hedging instruments:
Interest rate contracts (1)	Interest expense		(582	)		(825	)
Interest rate contracts	Derivatives		(3,130	)		(1,114	)
Commodity contracts	Derivatives		(4,438	)		(6,047	)
Total increase (decrease) in net income resulting from derivatives		$	(8,150	)	$	(7,986	)

Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives		(1,646	)		2,836
Cash paid for interest rate contract settlements	Interest expense		-			(370	)
Unrealized derivative losses (2)			(6,504	)		(10,452	)
Total increase (decrease) in net income resulting from derivatives		$	(8,150	)	$	(7,986	)

(1)

This represents Interest Rate Swap amounts reclassified out of AOCI and into earnings. During 2008 and 2009 we discontinued cash flow hedge accounting for various Interest Rate Swaps at different times. By the first quarter of 2009 we discontinued cash flow hedge accounting for the remaining Interest Rate Swaps. During the three months ended March 31, 2009 we reclassified $0.4 million out of AOCI relating to actual hedge settlements accounted for under hedge accounting. During the three months ended March 31, 2010 and 2009, we reclassified $0.6 million and $0.8 million out of AOCI relating to Interest Rate Swaps no longer designated for cash flow hedge accounting.

(2)

This activity represents unrealized losses in the interest expense and derivatives caption on our Condensed Consolidated Statements of Income.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our Condensed Consolidated Balance Sheets for the periods presented:

		Fair values as of March 31, 2010				Fair values as of December 31, 2009
	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities - current	$	-	$	7,445	$	-	$	7,710
Interest rate contracts	Derivative assets/liabilities - noncurrent		186		3,128		1,266		3,241
Commodity contracts	Derivative assets/liabilities - current		1,320		7,530		1,331		3,541
Commodity contracts	Derivative assets/liabilities - noncurrent		97		2,341		18		1,044
Total derivatives not designated as hedging instruments		$	1,603	$	20,444	$	2,615	$	15,536

Total fair value of derivative instruments		$	1,603	$	20,444	$	2,615	$	15,536

See Note 3 for a description of how the above-described financial instruments are valued.

The following table summarizes our interest expense, including the effect of the Interest Rate Swaps, for the periods presented:

	Three Months Ended March 31,
Source	2010		2009
Interest on Revolver	$	3,869	$	4,277
Debt issuance costs and other		1,384	$	591
Capitalized interest		-		(77	)
Interest rate swaps		582		825
Total interest expense	$	5,835	$	5,616

As of March 31, 2010, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of March 31, 2010, we did not own derivative instruments containing credit risk contingencies.

5. Equity Investments

In accordance with the equity method of accounting, we recognized earnings of $2.2 million and $1.6 million for the three months ended March 31, 2010 and 2009, with a corresponding increase in the investment. The joint ventures generally pay quarterly distributions on their cash flow. We received $2.7 million for three months ended March 31, 2010 and no distributions for the same period of 2009. Equity earnings related to the 50% interest in Coal Handling Solutions LLC are included in coal services revenues on the Condensed Consolidated Statements of Income, and equity earnings related to the 25% interest in Thunder Creek and 50% interest in Crosspoint are recorded in other revenues on the Condensed Consolidated Statements of Income. The equity investments for all joint ventures are included in the equity investments caption on the Condensed Consolidated Balance Sheets.

Summarized financial information of unconsolidated equity investments is as follows for the periods presented:

	March 31,		December 31,
	2010		2009
Current assets	$	36,243	$	32,996
Noncurrent assets	$	210,818	$	214,463
Current liabilities	$	6,862	$	4,898
Noncurrent liabilities	$	5,367	$	5,392

	Three Months Ended March 31,
	2010		2009
Revenues	$	16,959	$	14,632
Expenses	$	8,917	$	8,411
Net income	$	8,042	$	6,221

6. Partners’ Capital and Distributions

As of March 31, 2010, partners’ capital consisted of 51.9 million common units, representing a 98% limited partner interest, and a 2% general partner interest. As of March 31, 2010, affiliates of Penn Virginia, in the aggregate, owned an approximately 39% interest in us, consisting of 19.6 million common units, representing an approximately 37% limited partner interest, and a 2% general partner interest.

Net Income per Limited Partner Unit

Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period. Diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units. For the three months ended March 31, 2010 and 2009, average awards of 273,000 and 36,000 phantom units were excluded from the diluted net income per limited partner unit calculation because the inclusion of these phantom units would have had an antidilutive effect.

The following table reconciles the computation of net income to net income allocable to limited partners:

	Three Months Ended March 31,
	2010			2009

Net income	$	14,651		$	9,468
Adjustments:
Distributions payable on account of incentive distribution rights		(6,046	)		(6,035	)
Distributions payable on account of general partner interest		(498	)		(497	)
General partner interest in excess of distributions over earnings allocable to the general partner interest		326			428
Net income allocable to limited partners and participating securities	$	8,433		$	3,364
Adjustments:
Distributions to participating securities		(218	)		-
Participating securities’ allocable share of net income		127			-
Net income allocable to limited partners	$	8,342		$	3,364

Weighted average limited partner units, basic and diluted		51,846			51,799

Net income per limited partner unit, basic and diluted	$	0.16		$	0.06

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 any other agreements and (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:

				General
	Unitholders			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 periods presented:

	Three Months Ended March 31,
	2010		2009

Limited partner units	$	24,345	$	24,345
General partner interest (2%)		497		497
Incentive distribution rights		6,035		6,035
Phantom units		165		-
Total cash distributions paid	$	31,042	$	30,877

Total cash distributions paid per limited partner unit	$	0.47	$	0.47

On May 14, 2010, we will pay a $0.47 per unit quarterly distribution to unitholders of record on May 3, 2010. This per unit distribution remains unchanged from the previous distribution paid on February 12, 2010.

7. 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 and our subsidiaries totaled $1.2 million and $1.5 million for the three months ended March 31, 2010 and 2009. These costs are reflected in the general and administrative expenses caption on 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 $11.1 million and $7.2 million as of March 31, 2010 and December 31, 2009. These amounts are primarily due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (“PVOG LP”), and are related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (“PVR East Texas”), our wholly owned subsidiary, and PVOG LP. See “—Gathering and Processing Revenues.” These balances are included in the accounts payable caption on our Condensed Consolidated Balance Sheets.

Marketing Revenues

PVOG LP 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, Connect Energy markets all of PVOG LP’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 LP 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. Under the Master Services Agreement, PVOG LP paid fees to Connect Energy of $0.4 million for both the three months ended March 31, 2010 and 2009. These marketing revenues are included in the other revenues caption on our Condensed Consolidated Statements of Income.

Gathering and Processing Revenues

PVR East Texas and PVOG LP are parties to a Gas Gathering and Processing Agreement effective April 1, 2007. Pursuant to this agreement, PVR East Texas gathers and processes all of PVOG LP’s current and future gas production in certain areas of the Bethany Field in East Texas and redelivers the natural gas liquids (“NGLs”) to PVOG LP for a $0.3115 per million British thermal units (MMBtu) service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term ending August 31, 2021 and automatically renews

for additional one-year terms until terminated by either party. PVR East Texas began gathering and processing PVOG LP’s gas in June 2008. Pursuant to the Gas Gathering and Processing Agreement, PVOG LP paid fees to PVR East Texas of $0.7 million for both the three months ended March 31, 2010 and 2009. These gathering and processing revenues are recorded in the natural gas midstream revenues caption on our Condensed Consolidated Statements of Income.

Gas Purchases and Sales

In addition to the gathering and processing by PVR East Texas, PVOG LP sells the processed natural gas and NGLs to Connect Energy at PVR’s Crossroads Plant, Connect Energy transports them to the marketing location, and then Connect Energy resells such gas or NGLs to third parties. The sales price received by PVOG LP from Connect Energy for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. For the three months ended March 31, 2010 and 2009, PVOG LP received and recognized revenue of $ 18.2 million and $21.2 million from Connect Energy in connection with such sales. For the three months ended March 31, 2010 and 2009, we recorded $18.2 million and $21.2 million of natural gas midstream revenue and $18.2 million and $21.2 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties.

8. Unit-Based Compensation

The Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (the “LTIP”) permits the grant of common units, deferred common units, restricted units and phantom units to employees and directors of our general partner and its affiliates. We recognized compensation expense of $1.4 million and $1.4 million for the three months ended March 31, 2010 and 2009 related to the granting of common and deferred common units under the LTIP and the vesting of restricted units and phantom units granted under the LTIP. Common units and deferred common units granted under the LTIP are immediately vested, and we recognize compensation expense related to those grants on the grant date. Restricted units and phantom units granted under the LTIP vest over a three-year period, with one-third vesting in each year, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period. These compensation expenses are recorded in the general and administrative expenses caption on our Condensed Consolidated Statements of Income. In 2010, 205,319 phantom unit grants were made under our LTIP at a weighted average grant-date fair value of $23.15.

9. 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 periods presented:

	Three Months Ended March 31,
	2010		2009
Net income	$	14,651	$	9,468
Unrealized holding losses on derivative activities		-		(506	)
Reclassification adjustment for derivative activities		582		825
Comprehensive income	$	15,233	$	9,787

10. 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 or results of operations.

Environmental Compliance

As of March 31, 2010 and December 31, 2009, our environmental liabilities were $1.0 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.

Customer Credit Risk

For the three months ended March 31, 2010, two of our natural gas midstream segment customers accounted for $31.8 million and $21.7 million, or 15% and 11%, of our total consolidated revenues. At March 31, 2010, 23% of our consolidated accounts receivable related to these customers.

11. Segment Information

Our reportable segments are as follows:

Coal and Natural Resource Management — Our coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn revenues from other land management activities, such as selling standing timber, 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.

Natural Gas Midstream — 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 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. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. 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.

The following tables present a summary of certain financial information relating to our segments for the periods presented:

	Revenues				Operating income
	Three Months Ended March 31,				Three Months Ended March 31,
	2010		2009		2010			2009

Coal and natural resource management	$	33,560	$	38,252	$	20,361		$	24,974
Natural gas midstream		172,918		118,507		7,385			(3,047	)
Consolidated totals	$	206,478	$	156,759	$	27,746		$	21,927

Interest expense						(5,835	)		(5,616	)
Other						308			318
Derivatives						(7,568	)		(7,161	)
Consolidated net income					$	14,651		$	9,468

	Additions to property and equipment				DD&A expense
	Three Months Ended March 31,				Three Months Ended March 31,
	2010		2009		2010			2009

Coal and natural resource management	$	32	$	1,300	$	7,326		$	7,394
Natural gas midstream		7,954		17,006		10,492			9,109
Consolidated totals	$	7,986	$	18,306	$	17,818		$	16,503

	Total assets at
	March 31,		December 31,
	2010		2009

Coal and natural resource management	$	569,821	$	574,258
Natural gas midstream		626,187		633,802
Consolidated totals	$	1,196,008	$	1,208,060

12. New Accounting Standards

In January 2010, the Financial Accounting Standards Board issued guidance on increased fair-value measurement disclosures. The guidance requires us to make new disclosures about recurring or nonrecurring fair-value measurements including significant transfers into and out of level 1 and level 2 fair-value measurements and information on purchases, sales, issuances, and settlements on a gross basis in the reconciliation of level 3 fair-value measurements. The guidance also clarified existing fair-value measurement disclosure about the level of disaggregation, inputs, and valuation techniques. Except for the detail level 3 roll forward disclosures, this guidance is effective for annual and interim reporting beginning in the first quarter of 2010. The new disclosures about purchases, sales, issuances and settlements in the roll forward activity for level 3 fair-value measurements are effective for interim and annual reporting beginning in the first quarter of 2011.

In June of 2009, an amendment was issued providing guidance regarding the consolidation of variable interest entities (“VIE”). It requires reporting entities to evaluate former qualified special purpose entities for consolidation, changes the approach to determining a VIE’s primary beneficiary from a quantitative assessment to a qualitative assessment designed to identify a controlling financial interest, and increases the frequency of required reassessment to determine whether a company is the primary beneficiary of a VIE. It also clarifies, but does not significantly change, the characteristics that identify a VIE. The guidance requires additional year-end and interim disclosures for public and non-public companies. This amendment was effective for annual and interim reporting periods beginning after November 15, 2009. The adoption of this guidance had no impact on our financial statements.

13. Subsequent Event

In April 2010, we sold $300.0 million of unsecured senior notes due on April 15, 2018 (the “Senior Notes”) with an annual interest rate of 8.25% which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under our Revolver. We may redeem some or all of the Senior Notes at any time on or after April 15, 2014 at the redemption prices set forth in the Supplemental Indenture governing the Senior Notes and prior to such date at a “make-whole” redemption price. We may also redeem up to 35% of the Senior Notes prior to April 15, 2013 with cash proceeds received from certain equity offerings. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness or if we experience a

change of control, we must offer to repurchase the Senior Notes. The Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including our Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our current and future subsidiaries, which are also guarantors under our Revolver.

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, or 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:

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

our ability to access external sources of capital;

any impairment writedowns of our assets;

the relationship between natural gas, NGL and coal prices;

the projected demand for and supply of natural gas, NGLs and coal;

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

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

our ability to generate sufficient cash from our businesses to maintain and pay the quarterly distribution to our general partner and our unitholders;

the experience and financial condition of our coal lessees and natural gas midstream customers, including our lessees’ ability to satisfy their royalty, environmental, reclamation and other obligations to us and others;

operating risks, including unanticipated geological problems, incidental to our coal and natural resource management or natural gas midstream businesses;

our ability to acquire new coal reserves or natural gas midstream assets and new sources of natural gas supply and connections to third-party pipelines on satisfactory terms;

our ability to retain existing or acquire new natural gas midstream customers and coal lessees;

the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves and obtain favorable contracts for such production;

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

delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects and new processing plants in our natural gas midstream business;

environmental risks affecting the mining of coal reserves or the production, gathering and processing of natural gas;

the timing of receipt of necessary governmental permits by us or our lessees;

hedging results;

accidents;

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

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

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

other risks set forth in Item 1A of this report and in our Annual Report on Form 10-K for the year ended December 31, 2009.

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, 2009. 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 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 Notes thereto in Item 1. All dollar amounts presented in the tables that follow are in thousands unless otherwise indicated.

Overview of Business

We are a publicly traded Delaware limited partnership formed by Penn Virginia Corporation, or Penn Virginia, in 2001, and we are principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States.

Key Developments

During the three months ended March 31, 2010, the following general business developments and corporate actions had an impact, or will have impact, on the financial reporting of our results of operations. A discussion of these key developments follows:

2010 Commodity Prices

The average commodity prices for natural gas, crude oil and natural gas liquids, or NGLs, increased for the three months ended March 31, 2010 from the same period of 2009. NGLs refer to ethane, propane, iso butane, normal butane and pentane. The pricing of these commodities directly and indirectly drive our earnings.

Coal royalties, which accounted for 84% of the coal and natural resource management segment revenues for the three months ended March 31, 2010 and 80% for the same period in 2009, were lower as compared to 2009. Realized coal royalty per ton by region were slightly higher than 2009, but decreases in production in the higher royalty rate regions offset these higher royalty rates. We continue to benefit from long-term contract prices our lessees previously negotiated with their customers. However, the state of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity of the market deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees.

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 demand. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. Our derivative financial instruments include costless collars and swaps. Based upon current volumes, we have entered into hedging arrangements covering approximately 60% and 58% of our commodity-sensitive volumes in 2010 and 2011. We generally target hedging 50% to 60% of our commodity-sensitive volumes covering a two-year period.

PVR Midstream Agreement with Range Resources

On March 10, 2010, PVR Midstream and Range Resources Corporation, or Range, entered into an agreement to construct and operate gas gathering pipelines and compression facilities servicing Range in the Marcellus Shale development in Pennsylvania.

PVR Midstream and Range have agreed to an area of mutual interest, or AMI, that covers parts of Lycoming, Tioga and Bradford Counties in north central Pennsylvania, in which the producer currently holds a substantial acreage position. Within this AMI, PVR Midstream will construct gathering trunklines, smaller-diameter field gathering lines and compression facilities required to gather production from the AMI. The agreement provides significant firm gathering capacity in the system, and PVR Midstream will be compensated for the gathering and compression services provided through a combination of firm reservation charges and additional fees

based on delivered volumes. Excess capacity on the system and the location within a core area of Marcellus Shale development may provide opportunities for PVR Midstream to develop additional revenues by providing gathering and compression services to other third-party producers in the area.

PVR Midstream’s total capital investment in this system is anticipated to be in the range of $170 to $200 million and is expected to be expended between 2010 and 2015, with $35 to $40 million planned for 2010.

PVR Midstream Agreement to Construct Gas Gathering and Compression Facilities

On March 1, 2010, PVR Midstream entered into an agreement to construct and operate gas gathering pipelines and compression facilities servicing a private firm’s Marcellus Shale natural gas production in Wyoming County, Pennsylvania. Pursuant to the terms of the agreement, PVR Midstream will construct a gathering pipeline and compression facilities with the potential for additional system extensions. PVR Midstream’s 2010 capital investment in this system is anticipated to be in the range of $6 to $7 million, with potential future system extensions costing up to an additional $10 million.

Changes in Our Management

In connection with Penn Virginia’s reduction of its limited partner interest in Penn Virginia GP Holdings, L.P., or PVG, we implemented certain changes in management, as a result of which certain executive officers of Penn Virginia resigned as executive officers and directors of Penn Virginia Resource GP, LLC, or PVR GP, our general partner.

On March 8, 2010, A. James Dearlove resigned from his position as Chief Executive Officer of PVR GP, and on March 9, 2010, he resigned from his position as President and Chief Executive Officer of PVG GP, LLC, or PVG GP, the general partner of PVG. On March 8, 2010, the board of directors of PVR GP appointed William H. Shea, Jr. to the position of Chief Executive Officer of PVR GP, and on March 9, 2010 the board of directors of PVG GP appointed Mr. Shea to the positions of President and Chief Executive Officer of PVG GP.

On March 23, 2010, Frank A. Pici resigned from his position as Vice President and Chief Financial Officer of PVR GP, and his position as Vice President and Chief Financial Officer of PVG GP. On March 23, 2010, the board of directors of PVR GP appointed Robert B. Wallace to the position of Executive Vice President and Chief Financial Officer of PVR GP, and the board of directors of PVG appointed Mr. Wallace to the position of Executive Vice President and Chief Financial Officer of PVG GP.

On March 31, 2010, A. James Dearlove, Frank A. Pici and Nancy M. Snyder each resigned from their positions as directors on the board of directors of PVR GP. On March 31, 2010, Mr. Shea was appointed as a director on the board of directors of PVR GP and on the board of directors of PVG GP.

Senior Notes Offering

In April 2010, the Company sold $300.0 million of unsecured senior notes due on April 15, 2018 (the “Senior Notes”) with an annual interest rate of 8.25% which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under our revolving credit facility, or the Revolver.

Liquidity and Capital Resources

Cash Flows

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under our Revolver and proceeds from equity offerings. As discussed in more detail in “—Sources of Liquidity” below, as of March 31, 2010, we had availability of $180.3 million on the Revolver. After giving effect to the Senior Notes offering noted above, our remaining borrowing

capacity will be $472.9 million. We fund our debt service obligations and distributions to unitholders solely using cash generated from our operations. 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 distributions. However, our ability to meet these requirements in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control.

The following table summarizes our cash flow statements for the periods presented:

	Three Months Ended March 31,
	2010			2009
Cash flows from operating activities:
Net income contribution	$	14,651		$	9,468
Adjustments to reconcile net income to net cash provided by
operating activities (summarized)		26,643			25,591
Net changes in operating assets and liabilities		8,308			(686	)
Net cash provided by operating activities		49,602			34,373
Net cash used in investing activities		(7,714	)		(18,041	)
Net cash used in financing activities		(33,020	)		(13,135	)
Net increase in cash and cash equivalents	$	8,868		$	3,197

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the three months ended March 31, 2010 as compared to the same period in 2009 was driven by an increase in the natural gas midstream segment’s gross margin. Higher commodity prices for natural gas as well as NGLs increased our margins even though lower throughput volumes were experienced for the comparative periods. The increase was partially offset by a decrease in operating income, before depreciation, depletion and amortization (“DD&A”) expense from the coal and natural resource management segment primarily due to decreases in coal royalties and minimum rental forfeitures.

Cash Flows From Investing Activities

Net cash used in investing activities were primarily for capital expenditures. The following table sets forth our capital expenditures program, by segment, for the periods presented:

	Three Months Ended March 31,
	2010		2009
Coal and natural resource management
Acquisitions	$	29	$	1,256
Other property and equipment expenditures		3		44
Total		32		1,300

Natural gas midstream
Expansion capital expenditures		7,400		11,200
Other property and equipment expenditures		1,857		3,282
Total		9,257		14,482

Total capital expenditures	$	9,289	$	15,782

Our capital expenditures for the three months ended March 31, 2010 and 2009 consisted primarily of natural gas midstream expansion capital used to increase our operational footprint in our Panhandle System.

Cash Flows From Financing Activities

During the three months ended March 31, 2010, we had net repayments of outstanding borrowings of $2.0 million and distributions to partners of $31.0 million. During the same period of 2009, we had net borrowings of $27.0 million used to finance expansion projects and a quarterly distribution of $30.9 million to partners.

Certain Non-GAAP Financial Measures

We use non-GAAP measures to evaluate our business and performance. None of these measures should be considered an alternative to, or more meaningful than, net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP, or as indicators of our operating performance or liquidity.

	Three Months Ended
	March 31,
	2010			2009

Reconciliation of GAAP "Net income" to Non-GAAP
"Distributable cash flow"
Net income	$	14,651		$	9,468
Depreciation, depletion and amortization		17,818			16,503
Commodity derivative contracts:
Derivative losses included in net income		8,150			7,615
Cash receipts (payments) to settle derivatives for the period		(1,646	)		2,836
Equity earnings from joint venture, net of distributions		443			(1,559	)
Other capital expenditures		(1,857	)		(3,282	)

Distributable cash flow (a)	$	37,559		$	31,581

Distribution to Partners:

Limited partner units	$	24,345		$	24,345
Phantom units (b)		165			-
General partner interest		497			497
Incentive distribution rights (c)		6,035			6,035

Total cash distribution paid during period	$	31,042		$	30,877

Total cash distribution paid per unit during period	$	0.47		$	0.47

Reconciliation of GAAP "Net income" to Non-GAAP
"Net income as adjusted"
Net income	$	14,651		$	9,468
Adjustments for derivatives:
Derivative losses included in net income		8,150			7,615
Cash receipts (payments) to settle derivatives for the period		(1,646	)		2,836

Net income, as adjusted (d)	$	21,155		$	19,919

Allocation of net income, as adjusted:
General partner's interest in net income, as adjusted	$	6,348		$	6,313
Limited partners' interest in net income, as adjusted	$	14,807		$	13,606

Net income, as adjusted, per limited partner unit, basic and diluted	$	0.28		$	0.26

(a)

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

operating activities under GAAP. Distributable cash flow is not a measure of financial performance under GAAP and should not be considered as an alternative to cash flows from operating, investing or financing activities, as an indicator of cash flows, as a measure of liquidity or as an alternative to net income.

	(b)	Phantom unit grants were made in 2009 under our long-term incentive plan. Phantom units receive distribution rights; thus, we have presented distributions paid to phantom unit holders in our total distributions paid to Partners.
	(c)	In accordance with our partnership agreement, incentive distribution rights represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved.

(d)

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

Distributable cash flow for the first quarter of 2010 of $37.6 million was $6.0 million, or 19 percent higher, than the $31.6 million of distributable cash flow in the first quarter of 2009 primarily due to:

$9.0 million increase in natural gas midstream segment gross margin (adjusted for the cash impact of midstream derivatives) due to higher frac spreads;

$2.0 million increase in distributions, net of equity in earnings, from joint ventures; and

$1.4 million decrease in other capital expenditures.

These increases in distributable cash flow were partially offset by:

$4.7 million decrease in coal and natural resource management segment total revenues due to decreases in production by lessees, average coal royalties per ton and other revenue; and

$1.7 million increase in interest expense (adjusted for the cash impact of interest rate derivatives)

Sources of Liquidity

Long-Term Debt

Revolver. As of March 31, 2010, net of outstanding borrowings of $618.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $180.3 million on the Revolver. After giving effect to the Senior Notes offering noted below, our remaining borrowing capacity will be $472.9 million. The Revolver matures in December 2011 and 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. 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 1.25% if we select the base rate borrowing option or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver during the three months ended March 31, 2010 was approximately 2.5%. We do not have a public rating for the Revolver. A discussion of the applicable covenants and related compliance with respect to the Revolver is provided in the discussion of Financial Condition that follows.

Interest Rate Swaps. We have entered into interest rate swaps, or Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth the Interest Rate Swap positions as of March 31, 2010:

	Notional Amounts		Swap Interest Rates (1)
Term	(in millions)		Pay			Receive
March 2010 - December 2011	$	250.0		3.37	%	LIBOR
December 2011 - December 2012	$	100.0		2.09	%	LIBOR

(1)

References to LIBOR represent the 3-month rate.

The Interest Rate Swaps extend one year past the maturity of the current Revolver. After considering the applicable margin of 2.25% in effect as of March 31, 2010 the total interest rate on the $250.0 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.62% as of March 31, 2010.

Senior Notes. In April 2010, we sold $300.0 million of unsecured senior notes due on April 15, 2018 with an annual interest rate of 8.25% which is payable semi-annually in arrears on April 15 and October 15 of each year. The Senior Notes were sold at par, equating to an effective yield to maturity of approximately 8.25%. The net proceeds from the sale of the Senior Notes of approximately $292.6 million, after deducting fees and expenses of approximately $7.4 million, were used to repay borrowings under our Revolver. We may redeem some or all of the Senior Notes at any time on or after April 15, 2014 at the redemption prices set forth in the Supplemental Indenture governing the Senior Notes and prior to such date at a “make-whole” redemption price. We may also redeem up to 35% of the Senior Notes prior to April 15, 2013 with cash proceeds received from certain equity offerings. If we sell certain assets and do not reinvest the proceeds or repay senior indebtedness or if we experience a change of control, we must offer to repurchase the Senior Notes. The Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including our Revolver to the extent of the collateral securing that indebtedness. The obligations under the Senior Notes are fully and unconditionally guaranteed by our current and future subsidiaries, which are also guarantors under our Revolver.

Financial Condition

Covenant Compliance

The terms of the Revolver require us to maintain financial covenants. These covenants are as follows:

•

Total debt to consolidated EBITDA may not exceed 5.25 to 1.0. EBITDA, which is a non-GAAP measure, is generally defined in the PVR Revolver as PVR’s net income plus interest expense (net of interest income), depreciation, depletion and amortization expenses, and non-cash hedging activity and impairments.

•

Consolidated EBITDA to interest expense may not be less than 2.5 to 1.0.

As of March 31, 2010 and through the date of this filing, we were in compliance with all of the Revolver’s covenants. The following table summarizes the actual results of our covenant compliance for the period ended March 31, 2010:

Description of Covenant	Covenant		Actual Results
Debt to EBITDA		5.25		3.28
EBITDA to interest expense		2.50		7.62

In the event that we would be in default of our covenants under the Revolver, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our Condensed Consolidated Balance Sheets. 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 our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries.

Future Capital Needs and Commitments

After giving effect to the Senior Notes offering noted above, we believe that our remaining borrowing capacity of approximately $472.9 million will be sufficient for our 2010 capital needs and commitments. Our short-term cash requirements for operating expenses and quarterly distributions to our general partner and our unitholders are expected to be funded through operating cash flows. In 2010, we anticipate making capital expenditures, excluding acquisitions, of approximately $105.0 million, including anticipated maintenance capital of $16.0 million to $18.0 million. The majority of the 2010 capital expenditures are expected to be incurred in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of operating cash flows and borrowings under our Revolver. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by operating cash flows, borrowings under our Revolver and the issuances of additional debt and equity securities if available under commercially acceptable terms.

Part of our long-term strategy is to increase cash available for distribution to our unitholders by making acquisitions and other capital expenditures. Our ability to make these acquisitions and other capital expenditures in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating.

Results of Operations

Consolidated Review

The following table presents summary consolidated results for the periods presented:

	Three Months Ended March 31,
	2010			2009
Revenues	$	206,478		$	156,759
Expenses		178,732			134,832
Operating income		27,746			21,927
Other income (expense)		(13,095	)		(12,459	)
Net income	$	14,651		$	9,468

The following table presents a summary of certain financial information relating to our segments for the periods presented:

	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
For the Three Months Ended March 31, 2010:
Revenues	$	33,560		$	172,918		$	206,478
Cost of midstream gas purchased		-			(141,795	)		(141,795	)
Operating costs and expenses		(5,873	)		(13,246	)		(19,119	)
Depreciation, depletion and amortization		(7,326	)		(10,492	)		(17,818	)
Operating income	$	20,361		$	7,385		$	27,746

For the Three Months Ended March 31, 2009:
Revenues	$	38,252		$	118,507		$	156,759
Cost of midstream gas purchased		-			(100,620	)		(100,620	)
Operating costs and expenses		(5,884	)		(11,825	)		(17,709	)
Depreciation, depletion and amortization		(7,394	)		(9,109	)		(16,503	)
Operating income	$	24,974		$	(3,047	)	$	21,927

Coal and Natural Resource Management Segment

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 2009

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 periods presented:

	Three Months Ended March 31,						Favorable			%
	2010			2009			(Unfavorable)			Change
Financial Highlights
Revenues
Coal royalties	$	28,226		$	30,630		$	(2,404	)		(8	)%
Coal services		1,973			1,888			85			5	%
Timber		1,305			1,317			(12	)		(1	)%
Oil and gas royalty		744			703			41			6	%
Other		1,312			3,714			(2,402	)		(65	)%
Total revenues		33,560			38,252			(4,692	)		(12	)%

Expenses
Coal royalties		1,456			1,224			(232	)		(19	)%
Other operating		515			883			368			42	%
Taxes other than income		475			425			(50	)		(12	)%
General and administrative		3,427			3,352			(75	)		(2	)%
Depreciation, depletion and amortization		7,326			7,394			68			1	%
Total expenses		13,199			13,278			79			1	%

Operating income	$	20,361		$	24,974		$	(4,613	)		(18	)%

Other data

Coal royalty tons by region
Central Appalachia		3,929			4,658			(729	)		(16	)%
Northern Appalachia		1,038			1,057			(19	)		(2	)%
Illinois Basin		1,082			1,261			(179	)		(14	)%
San Juan Basin		2,194			1,772			422			24	%
Total		8,243			8,748			(505	)		(6	)%

Coal royalties revenues by region
Central Appalachia	$	18,530		$	21,683		$	(3,153	)		(15	)%
Northern Appalachia		1,950			1,951			(1	)		(0	)%
Illinois Basin		2,942			3,241			(299	)		(9	)%
San Juan Basin		4,804			3,755			1,049			28	%
	$	28,226		$	30,630		$	(2,404	)		(8	)%
Less coal royalties expenses (1)		(1,456	)		(1,224	)		(232	)		(19	)%
Net coal royalties revenues	$	26,770		$	29,406		$	(2,636	)		(9	)%

Coal royalties per ton by region ($/ton)
Central Appalachia	$	4.72		$	4.66		$	0.06			1	%
Northern Appalachia		1.88			1.85			0.03			2	%
Illinois Basin		2.72			2.57			0.15			6	%
San Juan Basin		2.19			2.12			0.07			3	%
	$	3.42		$	3.50		$	(0.08	)		(2	)%
Less coal royalties expenses (1)		(0.17	)		(0.14	)		(0.03	)		(21	)%
Net coal royalties revenues	$	3.25		$	3.36		$	(0.11	)		(3	)%

(1)

Our coal royalties expense is incurred primarily in the Central Appalachian region.

Revenues

Coal royalties revenues decreased due to a shift in production mix to lower royalty leases, primarily to fixed rate leases in the San Juan Basin from the higher royalty Central Appalachian region. The average royalty rates received in all regions was relatively consistent for the comparative periods.

Coal production decreased due to lower longwall mining operations in the Central Appalachian region as operations moved onto adjacent reserves and the closure of a mine in the Illinois Basin due to adverse geological conditions. These production decreases were partially offset by production increases in the San Juan Basin resulting from the start up of a mine during 2009 and improved mining conditions.

Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fees, decreased due to forfeited minimum rentals recognized in the first quarter of 2009 for a property that was not mined in the statutory time period.

Expenses

Coal royalties expenses increased due to an increase in mining activity by our lessees from subleased properties in the Central Appalachian region where our coal royalties expense is primarily incurred. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and those of other mineral owners.

Operating expenses decreased due to the timing of core hole drilling and other geological studies of coal seams and reserves.

DD&A expenses were relatively consistent for the comparative periods. On a per ton basis, coal depletion increased to $0.62 per ton in the first quarter of 2010 from $0.57 per ton in the first quarter of 2009. The increase in depletion rates was offset by the decrease in production.

Natural Gas Midstream Segment

Three Months Ended March 31, 2010 Compared with Three Months Ended March 31, 20009

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 presented:

	Three Months Ended March 31,					Favorable
	2010		2009			(Unfavorable)			% Change
Financial Highlights
Revenues
Residue gas	$	94,896	$	81,194		$	13,702			17	%
Natural gas liquids		66,643		30,606			36,037			118	%
Condensate		6,736		2,903			3,833			132	%
Gathering, processing and transportation fees		2,334		2,676			(342	)		(13	)%
Total natural gas midstream revenues (1)		170,609		117,379			53,230			45	%
Equity earnings in equity investment		1,683		1,119			564			50	%
Producer services		626		9			617			6856	%
Total revenues		172,918		118,507			54,411			46	%

Expenses
Cost of midstream gas purchased (1)		141,795		100,620			(41,175	)		(41	)%
Operating		7,292		6,783			(509	)		(8	)%
Taxes other than income		1,043		798			(245	)		(31	)%
General and administrative		4,911		4,244			(667	)		(16	)%
Depreciation and amortization		10,492		9,109			(1,383	)		(15	)%
Total operating expenses		165,533		121,554			(43,979	)		(36	)%

Operating income	$	7,385	$	(3,047	)	$	10,432			342	%

Operating Statistics
System throughput volumes (MMcf)		27,725		32,280			(4,555	)		(14	)%
Daily throughput volumes (MMcfd)		308		359			(51	)		(14	)%

Gross margin	$	28,814	$	16,759		$	12,055			72	%
Cash impact of derivatives		780		3,792			(3,012	)		(79	)%
Gross margin, adjusted for impact of derivatives	$	29,594	$	20,551		$	9,043			44	%

Gross margin ($/Mcf)	$	1.04	$	0.52		$	0.52			100	%
Cash impact of derivatives ($/Mcf)		0.03		0.12			(0.09	)		(75	)%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	1.07	$	0.64		$	0.43			67	%

(1)

In the three months ended March 31, 2010 and 2009, we recorded $18.2 million and $21.2 million of natural gas midstream revenues and $18.2 million and $21.2 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties. These transactions do not impact the gross margin.

Gross Margin

Gross 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.

The gross margin increase was a result of higher commodity pricing and higher fractionation, or frac, spreads partially offset by decreased system throughput volumes. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis. Not all of our system throughput volumes are processed through gas processing plants as some of our systems are only gathering facilities. Of the systems with gas processing capabilities, our processed volumes remained relatively consistent for the comparative periods. Processed volumes at our Crossroads facility increased due to the addition of new producer gas, which was offset by a decrease in processed volumes at our other processing facilities due to lack of producer drilling and natural declines of natural gas production.

We generated a majority of our gross margin from contractual arrangements under which the gross 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. On a per Mcf basis, adjusted for the impact of our commodity derivative instruments, our gross margin increased by $0.43, or 67% as compared to the three months ended March 31, 2009. This favorable increase was moderately impacted by commodity derivatives as a result of higher commodity prices during the first quarter of 2010.

Revenues Other Than Gross Margin

Equity earnings in equity investment have grown due to mainline volume increases in the Powder River Basin. Producer services revenues increased due to the relative increase in commodity prices.

Expenses

Operating expenses increased due to prior and current years’ acquisitions, expansion projects, compressor rentals and labor costs. Increased costs for compressor rentals and labor costs were incurred due to expanding our footprint in the Panhandle System.

Taxes other than income increased due to higher property taxes. The increase in property taxes was a result of acquisitions and plant expansions.

General and administrative expenses increased due to increased staffing and related benefit costs.

Depreciation and amortization expenses increased primarily due to acquisitions and capital expansions on the Panhandle System, including the Sweetwater plant acquisition and Spearman plant construction.

Other

Our other results consist of interest expense and derivative gains and losses. The following table sets forth a summary of certain financial data for our other results for the periods presented:

	Three Months Ended March 31,
	2010			2009
Operating income	$	27,746		$	21,927
Other income (expense)
Interest expense		(5,835	)		(5,616	)
Other		308			318
Derivatives		(7,568	)		(7,161	)
Net income	$	14,651		$	9,468

Interest Expense. Our consolidated interest expense for the periods presented is comprised of the following:

	Three Months Ended March 31,
Source	2010		2009
Interest on Revolver	$	3,869	$	4,277
Debt issuance costs and other		1,384	$	591
Capitalized interest		-		(77	)
Interest rate swaps		582		825
Total interest expense	$	5,835	$	5,616

Interest expense incurred on borrowings under our Revolver for the three months ended March 31, 2010 decreased from the comparative period in 2009 due to lower interest rates. This decrease was more than offset by the effects of an increase in our weighted average borrowings due to our capital spending program and an increase in non-cash interest expense related to debt issuance costs incurred in March 2009. The Interest Rate Swaps, which establish fixed interest rates on a portion of the outstanding borrowings under the Revolver, have also increased the total interest expense.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices affecting fair values for NGL, crude oil and natural gas prices, as well as the Interest Rate Swaps.

Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position and our own credit risk for derivatives in a liability position.

Our derivative activity for the periods presented is summarized below:

	Three Months Ended March 31,
	2010			2009
Interest Rate Swap unrealized derivative loss	$	(704	)	$	(158	)
Interest Rate Swap realized derivative loss		(2,426	)		(956	)
Natural gas midstream commodity unrealized derivative loss		(5,218	)		(9,839	)
Natural gas midstream commodity realized derivative gain		780			3,792
Total derivative loss	$	(7,568	)	$	(7,161	)

Environmental Matters

Our operations and those of our coal 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 on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. 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 environment-related material adverse impact on our financial condition or results of operations.

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.

Critical Accounting 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. Our most critical accounting estimates which involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2009 and remained unchanged as of March 31, 2010.

New Accounting Standards

See Note 12 to the Condensed Consolidated Financial Statements for a description of new accounting standards.

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 as follows:

Price Risk

Interest Rate Risk

Customer Credit Risk

As a result of our risk management activities as discussed below, we are also exposed to counterparty risk with financial institutions with whom we enter into these risk management positions. Sensitivity to these risks has heightened due to the deterioration of the global economy, including financial and credit markets.

We have completed a number of acquisitions in recent years. In conjunction with our accounting for these acquisitions, it was necessary for us to estimate the values of the assets acquired and liabilities assumed, which involved the use of various assumptions. The most significant assumptions, and the ones requiring the most judgment, involve the estimated fair values of property, plant and equipment, and the resulting amount of goodwill, if any. Changes in operations, further decreases in commodity prices, changes in the business environment or further deteriorations of market conditions could substantially alter management’s assumptions and could result in lower estimates of values of acquired assets or of future cash flows. If these events occur, it is reasonably possible that we could record a significant impairment loss on our Condensed Consolidated Statements of Income.

Price Risk

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 segment. The derivative financial instruments are placed with major financial institutions that we believe are of acceptable credit risk. The fair values of our price derivative financial instruments are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At March 31, 2010, we reported a net commodity derivative liability related to our natural gas midstream segment of $8.5 million that is with six counterparties and is substantially concentrated with four of those counterparties. This concentration may impact our overall credit risk, either positively or negatively, in that these counterparties may be similarly affected by changes in economic or other conditions. We neither paid nor received collateral with respect to our derivative positions. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

For the three months ended March 31, 2010, we reported net derivative losses of $7.6 million. Because we no longer use hedge accounting for our commodity derivatives, we recognize changes in fair value in earnings currently in the derivatives caption on our Condensed Consolidated Statements of Income. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of our commodity derivative contracts. Our results of operations are affected by the volatility of unrealized gains and losses and changes in fair value, which fluctuate with changes in natural gas, crude oil and NGL prices. These fluctuations could be significant in a volatile pricing environment. See Note 4 to the Condensed Consolidated Financial Statements for a further description of our derivatives program.

The following table lists our commodity derivative agreements and their fair values as of March 31, 2010:

	Average								Fair Value at
	Volume Per				Weighted Average Price				March 31,
	Day		Swap Price		Put		Call		2010

Crude Oil Collar	(barrels)				($ per barrel)
Second Quarter 2010 through Fourth Quarter 2010		1,750			$	68.86	$	80.54	$	(3,309	)
First Quarter 2011 through Fourth Quarter 2011		400			$	75.00	$	98.50	$	35

Natural Gas Purchase Swap	(MMBtu)		($ per MMBtu)
Second Quarter 2010 through Fourth Quarter 2010		7,100	$	5.885					$	(3,133	)
First Quarter 2011 through Fourth Quarter 2011		6,500	$	5.796					$	(1,043	)

Ethane Swap	(gallons)		($ per gallon)
Second Quarter 2010		72,000	$	0.735					$	1,062

NGL - Natural Gasoline Collar	(gallons)				($ per gallon)
Third Quarter 2010 through Fourth Quarter 2010		42,000			$	1.55	$	2.03	$	(212	)
First Quarter 2011 through Fourth Quarter 2011		95,000			$	1.57	$	1.94	$	(2,025	)

Settlements to be received in subsequent period									$	171

									$	(8,454	)

We estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of our crude oil collars by $2.5 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of our crude oil collars by $2.2 million. We estimate that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of our natural gas purchase swaps by $4.1 million. We estimate that a $1.00 per MMBtu decrease in the natural gas price would decrease the fair value of our natural gas purchase swaps by $4.1 million. We estimate that a $0.10 per gallon increase in the natural gasoline (an NGL) price would decrease the fair value of our natural gasoline collar by $3.0 million. We estimate that a $0.10 per gallon decrease in the natural gasoline price would increase the fair value of our natural gasoline collar by $2.8 million. We estimate that a $0.05 per gallon increase in the ethane (an NGL) price would decrease the fair value of our ethane swap by $0.3 million. We estimate that a $0.10 per gallon decrease in the ethane price would increase the fair value of our ethane swap by $0.3 million.

We estimate that, excluding the effects of derivative positions described above, for every $1.00 per MMBtu increase or decrease in the natural gas price, our natural gas midstream gross margin and operating income for the remainder of 2010 would increase or decrease by $3.8 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, our natural gas midstream gross margin and operating income for the remainder of 2010 would increase or decrease by $5.9 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in our gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of March 31, 2010, we had $618.1 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to establish fixed interest rates on a portion of the outstanding borrowings under the Revolver. From March 2010 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million, or 40.4% of our outstanding indebtedness under the Revolver as of March 31, 2010, with us paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, or 16.1% of our outstanding indebtedness under the Revolver as of March 31, 2010, with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The Interest Rate Swaps extend one year past the current maturity of the Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through the Interest Rate Swaps) as of March 31, 2010 would cost us approximately $3.7 million in additional interest expense per year.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. Therefore, our results of operations are affected by the volatility of changes in fair value, which fluctuates with

changes in interest rates. These fluctuations could be significant. See Note 4 to the Condensed Consolidated Financial Statements for a further description of our derivatives program.

Customer Credit Risk

We are exposed to the credit risk of our natural gas midstream customers and coal lessees. For the three months ended March 31, 2010, two of our natural gas midstream segment customers accounted for $31.8 million and $21.7 million, or 15% and 11%, of our total consolidated revenues. At March 31, 2010, 23% of our consolidated accounts receivable related to these customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these two natural gas midstream customers.

This customer concentration increases our exposure to credit risk on our accounts receivables, because the financial insolvency of any of these customers could have a significant impact on our results of operations. If our natural gas midstream customers or coal lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations to us. Any material losses as a result of customer or lessee defaults could harm and have an adverse effect on our business, financial condition or results of operations. Substantially all of our trade accounts receivable are unsecured.

To mitigate the risks of nonperformance by our natural gas midstream customers, we perform ongoing credit evaluations of our existing customers. We monitor individual customer payment capability in granting credit arrangements to new customers by performing credit evaluations, seek to limit credit to amounts we believe the customers can pay and maintain reserves we believe are adequate to cover exposure for uncollectible accounts. As of March 31, 2010, no receivables were collateralized, and we had a $0.6 million allowance for doubtful accounts, of which the majority related to our natural gas midstream segment.

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, 2010. 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, 2010, 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.

PART II. OTHER INFORMATION

Item 1A Risk Factors

Concerns about the environmental impacts of fossil-fuel emissions, including perceived impacts on global climate change, are resulting in increased regulation of emissions of greenhouse gases in many jurisdictions and increased interest in and the likelihood of further regulation, which could significantly affect our coal royalties revenues.

Global climate change continues to attract considerable public and scientific attention. Several widely publicized scientific reports have engendered widespread concern about the impacts of human activity, especially fossil fuel combustion, on global climate change. Legislative attention in the United States is being paid to global climate change and to reducing greenhouse gas emissions, particularly from coal combustion by power plants. Such legislation was introduced in Congress in the last several years to reduce greenhouse gas emissions in the United States and further proposals or amendments are likely to be offered in the future. In anticipation of the endangerment finding of the Environmental Protection Agency, or the EPA, regarding greenhouse gas emissions (which was finalized in December 2009), the agency proposed two sets of rules regarding possible future regulation of greenhouse gas emissions under the Clean Air Act. Enactment of laws, passage of regulations regarding greenhouse gas emissions by the United States or some of its states, or other actions to limit carbon dioxide emissions could result in electric generators switching from coal to other fuel sources. This may adversely affect the use of and demand for fossil fuels, particularly coal. Also, in 2009, the EPA announced that it will consider whether to reclassify byproducts of coal combustion as hazardous waste. It is not possible to determine with certainty the potential permitting requirements or performance standards that may be imposed on the disposal of coal combustion byproducts, by future regulations or lawsuits. If rules are adopted to regulate the management and disposal of these by-products, they could add additional costs to the use of coal as a fuel and may encourage power plant operators to switch to a different fuel.

Delays in our lessees obtaining mining permits and approvals, or the inability to obtain required permits and approvals, could have an adverse effect on our coal royalties revenues.

Mine operators, including our lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules are complex and can change over time. For example, on March 26, 2010, the EPA announced a proposal to exercise its Section 404(c) “veto” power with regard to the Spruce No. 1 Surface Mine in West Virginia, which was previously permitted in 2007. This would be the first time the EPA’s Section 404(c) “veto” power would be applied to a previously permitted project. Moreover, on April 1, 2010, the EPA issued interim final guidance substantially revising the environmental review of Section 402 and Section 404 permits by state and federal agencies. As an example of the significance of this guidance, the EPA also published on April 1, 2010 a proposed determination to prohibit, restrict or deny a permit issued under Section 404 to Mingo Logan Coal Company for the discharge of dredged fill in connection with the construction of various fills and sedimentation ponds. Of course, this guidance has just been issued and it remains to be seen how it will be applied by the EPA and whether it will be subject to judicial challenge by affected states or private parties. These initiatives have extended the time required to obtain permits for coal mining and we anticipate further delays in obtaining permits and that the costs associated with obtaining and complying with those permits will increase substantially. It is possible that some projects may not be able to obtain these permits because of the manner in which these rules are being interpreted and applied. Limitations on our lessees’ ability to conduct their mining operations due to the inability to obtain or renew necessary permits, or due to uncertainty, litigation or delays associated with the eventual issuance of these permits, could have an adverse effect on our coal royalties revenues.

Our lessees’ mining operations are subject to extensive and costly laws and regulations, which could increase operating costs and limit our lessees’ ability to produce coal, which could have an adverse effect on our coal royalties revenues.

Our lessees are subject to numerous and detailed federal, state and local laws and regulations affecting coal mining operations, including laws and regulations pertaining to employee health and safety, permitting and licensing requirements, air quality standards, water pollution, plant and wildlife protection, reclamation and restoration of mining properties after mining is completed, the discharge of materials into the environment, surface subsidence

from underground mining and the effects that mining has on groundwater quality and availability. Numerous governmental permits and approvals are required for mining operations. Our lessees are required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any proposed exploration for or production of coal may have upon the environment. The costs, liabilities and requirements associated with these regulations may be significant and time-consuming and may delay commencement or continuation of exploration or production operations. Recent mining accidents in West Virginia and Kentucky have received national attention and instigated responses at the state and national level that are likely to result in increased scrutiny of current safety practices and procedures at all mining operations, particularly underground mining operations. Moreover, workplace accidents, such as the April 5, 2010, Upper Big Branch Mine, West Virginia incident, may result in more stringent enforcement as well as the development of new laws and regulations. The possibility exists that new laws or regulations (or judicial interpretations of existing laws and regulations) may be adopted in the future that could materially affect our lessees’ mining operations, either through direct impacts such as new requirements impacting our lessees’ existing mining operations, or indirect impacts such as new laws and regulations that discourage or limit coal consumers’ use of coal. Any of these direct or indirect impacts could have an adverse effect on our coal royalties revenues.

Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of cleanup and site restoration costs and liens and, to a lesser extent, the issuance of injunctions to limit or cease operations. Our lessees may also incur costs and liabilities resulting from claims for damages to property or injury to persons arising from their operations. If our lessees are required to pay these costs and liabilities and if their financial viability is affected by doing so, then their mining operations and, as a result, our coal royalties revenues, could be adversely affected.

Expanding our natural gas midstream business by constructing new gathering systems, pipelines and processing facilities subjects us to construction risks.

One of the ways we may grow our natural gas midstream business is through the construction of additions to existing gathering, compression and processing systems. The construction of a new gathering system or pipeline, the expansion of an existing pipeline through the addition of new pipe or compression and the construction of new processing facilities involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. Our access to such capital is currently adversely impacted by the state of the global economy, including financial and credit markets. If we do undertake these projects, they may not be completed on schedule, or at all, or at the anticipated cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For example, the construction of gathering facilities requires the expenditure of significant amounts of capital, which may exceed our estimates. Generally, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. As a result, there is the risk that new facilities, including the facilities we are constructing in the Marcellus Shale formation in north central Pennsylvania under our contract with Range Resources Corporation, or Range, may not be able to attract enough natural gas to achieve our expected investment return, which could have a material adverse effect on our business, results of operations or financial condition.

Federal and/or state legislation and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays in the exploitation of the Marcellus Shale formation, which may adversely affect the supply of natural gas to our planned Marcellus Shale system.

The United States Congress is currently considering legislation to amend the Safe Drinking Water Act to eliminate an existing exemption for hydraulic fracturing activities. Similar legislation is under consideration in various states, including New York, and state environmental agencies may impose new requirements on these practices under existing laws. Hydraulic fracturing involves the injection of water, sand and additives under pressure into rock formation to stimulate natural gas production. Range and other producers who are active in the Marcellus Shale formation use hydraulic fracturing to produce commercial quantities of natural gas and oil from shale formations such as the Marcellus Shale. Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal and/or state levels, exploration and production activities that entail

hydraulic fracturing could be subject to additional regulation and permitting requirements, which could include public review and possibly even rights to challenge permitting. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay the development of unconventional gas resources from shale formations which are not commercial without the use of hydraulic fracturing. In this case, the ability of such producers to supply our planned Marcellus Shale system with natural gas may be diminished, which could, in turn, adversely affect our revenues.

Item 6 Exhibits

10.1	Employment Agreement between Robert B. Wallace and Penn Virginia Resource GP, LLC dated March 23, 2010 (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on March 24, 2010).

10.2	Amended and Restated Employment Agreement between William H. Shea, Jr. and Penn Virginia Resource GP, LLC dated March 23, 2010 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on March 24, 2010).

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 6, 2010	By:	/s/ Robert B. Wallace
			Robert B. Wallace
			Executive Vice President and Chief Financial Officer

Date:	May 6, 2010	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller