PVR Partners, L. P. 10Q 2010 Q3 Quarterly report

PVR Partners, L. P. (PVR) Inactive 10-Q2010 Q3 Quarterly report

Content analysis

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 September 30, 2010

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

For the transition period from to

Commission File Number: 1-16735

PENN VIRGINIA RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

23-3087517

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)

FIVE RADNOR CORPORATE CENTER, SUITE 500

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 975-8200

(Registrant’s telephone number, including area code)

FOUR RADNOR CORPORATE CENTER, SUITE 200

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.

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 October 19, 2010, 52,293,381 common units representing limited partner interests were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX


		Page

PART I.	Financial Information

Item 1.	Financial Statements

	Consolidated Statements of Income for the Three and Nine Months Ended September 30, 2010 and 2009		1

	Consolidated Balance Sheets as of September 30, 2010 and December 31, 2009		2

	Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2010 and 2009		3

	Notes to Consolidated Financial Statements		4

	Forward-Looking Statements		15

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		17

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		34

Item 4.	Controls and Procedures		37

PART II.	Other Information

Item 1.	Legal Proceedings		38

Item 1A.	Risk Factors		38

Item 6.	Exhibits		40

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenues
Natural gas midstream	$	180,207		$	118,443		$	497,362		$	348,882
Coal royalties		34,983			29,821			98,088			90,448
Coal services		1,975			1,869			5,976			5,502
Other		5,664			5,492			17,313			16,971

Total revenues		222,829			155,625			618,739			461,803


Expenses
Cost of gas purchased		151,657			92,355			415,111			285,129
Operating		11,748			9,836			32,317			29,296
General and administrative		8,392			7,767			31,576			24,271
Depreciation, depletion and amortization		18,702			17,851			54,783			51,971

Total expenses		190,499			127,809			533,787			390,667


Operating income		32,330			27,816			84,952			71,136

Other income (expense)
Interest expense		(10,639	)		(6,505	)		(25,368	)		(18,486	)
Other		103			323			615			969
Derivatives		(11,020	)		(2,810	)		(11,514	)		(12,005	)


Net income	$	10,774		$	18,824		$	48,685		$	41,614


General partner’s interest in net income	$	6,187		$	6,291		$	18,842		$	18,576


Limited partners’ interest in net income	$	4,587		$	12,533		$	29,843		$	23,038


Basic and diluted net income per limited partner unit (see Note 7)	$	0.09		$	0.24		$	0.57		$	0.43

Weighted average number of units outstanding, basic and diluted		52,293			51,799			52,034			51,799

The accompanying notes are an integral part of these Consolidated Financial Statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	September 30, 2010			December 31, 2009
Assets
Current assets
Cash and cash equivalents	$	13,131		$	8,659
Accounts receivable, net of allowance for doubtful accounts		80,087			82,321
Derivative assets		148			1,331
Other current assets		7,095			4,468

Total current assets		100,461			96,779


Property, plant and equipment		1,237,475			1,162,070
Accumulated depreciation, depletion and amortization		(305,075	)		(261,226	)

Net property, plant and equipment		932,400			900,844


Equity investments		85,102			87,601
Intangible assets, net		78,648			83,741
Derivative assets		6			1,284
Other long-term assets		52,402			37,811


Total assets	$	1,249,019		$	1,208,060


Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	67,847		$	60,679
Accrued liabilities		26,153			9,726
Deferred income		3,531			3,839
Derivative liabilities		13,430			11,251

Total current liabilities		110,961			85,495


Deferred income		11,213			5,482
Other liabilities		18,087			16,191
Derivative liabilities		4,250			4,285
Senior notes		300,000			—
Revolving credit facility		365,000			620,100

Partners’ capital
Common units (52,293,381 at September 30, 2010 and 51,798,895 at December 31, 2009)		433,269			471,068
General partner interest		6,131			6,834
Accumulated other comprehensive income		108			(1,395	)

Total partners’ capital		439,508			476,507

Total liabilities and partners’ capital	$	1,249,019		$	1,208,060

The accompanying notes are an integral part of these Consolidated Financial Statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Cash flows from operating activities
Net income	$	10,774		$	18,824		$	48,685		$	41,614
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		18,702			17,851			54,783			51,971
Commodity derivative contracts:
Total derivative losses		11,020			3,667			12,604			14,235
Cash receipts (payments) to settle derivatives		(2,435	)		(314	)		(6,493	)		4,135
Non-cash interest expense		1,633			1,416			4,243			3,149
Non-cash unit-based compensation		130			1,500			6,017			1,500
Equity earnings, net of distributions received		110			(1,385	)		2,500			(2,456	)
Other		(109	)		(300	)		(721	)		(932	)
Changes in operating assets and liabilities:
Accounts receivable		(9,102	)		1,341			1,828			15,379
Accounts payable		15,254			1,910			10,768			(11,477	)
Accrued liabilities		8,188			359			12,815			3,776
Deferred income		4,695			896			5,423			(1,447	)
Other asset and liabilities		(4,865	)		(2,898	)		(5,638	)		(3,022	)

Net cash provided by operating activities		53,995			42,867			146,814			116,425


Cash flows from investing activities
Acquisitions		(6	)		(27,648	)		(17,870	)		(29,510	)
Additions to property, plant and equipment		(33,240	)		(11,523	)		(57,973	)		(43,781	)
Other		315			300			985			872

Net cash used in investing activities		(32,931	)		(38,871	)		(74,858	)		(72,419	)


Cash flows from financing activities
Distributions to partners		(31,205	)		(31,211	)		(93,389	)		(92,966	)
Proceeds from issuance of senior notes		—			—			300,000			—
Proceeds from borrowings		44,000			52,000			110,000			93,000
Repayments of borrowings		(25,490	)		(21,000	)		(365,100	)		(33,000	)
Net proceeds from issuance of partners’ capital		160			—			182			—
Debt issuance costs		(10,430	)		—			(19,177	)		(9,258	)

Net cash used in financing activities		(22,965	)		(211	)		(67,484	)		(42,224	)

Net increase (decrease) in cash and cash equivalents		(1,901	)		3,785			4,472			1,782
Cash and cash equivalents – beginning of period		15,032			7,481			8,659			9,484

Cash and cash equivalents – end of period	$	13,131		$	11,266		$	13,131		$	11,266


Supplemental disclosure:
Cash paid for interest	$	3,931		$	6,444		$	15,327		$	18,446

The accompanying notes are an integral part of these Consolidated Financial Statements.

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 2010

1.	Organization

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “us” or “our”) is a publicly traded Delaware limited partnership formed 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, Texas and Pennsylvania. 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. We 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 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.

As of September 30, 2010, partners’ capital consisted of 52.3 million common units, representing a 98% limited partner interest, and a 2% general partner interest. As of September 30, 2010, PVG owned an approximate 39% interest in us, consisting of 19.6 million common units, representing an approximately 37% limited partner interest, and a 2% general partner interest.

On September 21, 2010, the Partnership announced that it had entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among the Partnership, Penn Virginia Resource GP, LLC (“PVR GP”), Penn Virginia GP Holdings, L.P. (“PVG”) PVG GP, LLC (“PVG GP”), and PVR Radnor, LLC (“Merger Sub”), a wholly owned subsidiary of the Partnership, pursuant to which PVG and PVG GP will be merged into Merger Sub, with Merger Sub as the surviving entity (the “Merger”). Merger Sub will subsequently be merged into our general partner, PVR GP, with PVR GP being the surviving entity. In the transaction, PVG unitholders will receive consideration of 0.98 common units in the Partnership for each common unit in PVG representing aggregate consideration of approximately 38.3 million common units in the Partnership. Pursuant to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of the Partnership, the incentive distribution rights held by our general partner will be extinguished, the 2.0% general partner interest in the Partnership held by our general partner will be converted into a noneconomic interest and approximately 19.6 million common units in the Partnership owned by PVG will be cancelled.

The terms of the Merger Agreement were unanimously approved by our conflicts committee, comprised of independent directors, of the board of directors of our general partner, by the board of directors of our general partner, by the PVG conflicts committee, comprised of independent directors, of the board of directors of PVG’s general partner, and by the board of directors of PVG’s general partner (in each case with the chief executive officer of each general partner recusing himself from the board of directors approvals).

recommendation to PVG’s unitholders with respect to the Merger or the conflicts committee of the board of directors or the board of directors of our general partner changes its recommendation to the Partnership’s unitholders with respect to the Merger.

After the Merger, the board of directors of our general partner, PVR GP, is expected to consist of nine members, six of whom are expected to be the existing members of the board and three of whom are expected to be the three existing members of the conflicts committee of the board of directors of PVG’s general partner.

The Merger Agreement is subject to customary closing conditions including, among other things, (i) approval by the affirmative vote of the holders of a majority of our common units outstanding and entitled to vote at a meeting of the holders of our common units, (ii) approval by the affirmative vote of the holders of a majority of PVG’s common units outstanding and entitled to vote at a meeting of the holders of PVG’s common units, (iii) receipt of applicable regulatory approvals, (iv) the effectiveness of a registration statement on Form S-4 with respect to the issuance of our common units in connection with the Merger, (v) receipt of certain tax opinions, (vi) approval for listing our common units to be issued in connection with the Merger on the New York Stock Exchange and (vii) the execution of our Fourth Amended and Restated Agreement of Limited Partnership.

Current holders of our common units (the “Partnership unitholders”) will continue to own their existing Partnership common units. Following the Merger, we will be owned approximately 46% by current Partnership unitholders and approximately 54% by former PVG unitholders. Our common units will continue to be traded on the New York Stock Exchange under the symbol “PVR” following the Merger.

PVG will be considered the surviving consolidated entity for accounting purposes, while we will be the surviving consolidated entity for legal and reporting purposes. The Merger will be accounted for as an equity transaction. Therefore, the changes in PVG’s ownership interest as a result of the Merger will not result in gain or loss recognition.

2.	Basis of Presentation

Our 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 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 Consolidated Financial Statements have been included. Our 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 and nine months ended September 30, 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 our Consolidated Financial Statements were issued and concluded that no subsequent events have occurred that would require recognition in the Consolidated Financial Statements or disclosure in these Notes.

Certain reclassifications have been made to conform to the current period’s presentation of taxes other than income. Historically, we reported taxes other than income as a separate component of expenses. We have reclassified the components of taxes other than income, which primarily related to property taxes and payroll taxes, to operating expense and general and administrative expense for all periods presented.

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 September 30, 2010, the carrying values of all of these financial instruments, except the long-term debt with fixed interest rates, 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. The fair value of our fixed-rate long-term debt is estimated based on the published market prices for the same or similar issues. As of September 30, 2010, the fair value of our fixed-rate debt was $311.3 million.

Recurring Fair Value Measurements

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


				Fair Value Measurements at September 30, 2010, Using
Description	Fair Value Measurements at September 30, 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 liabilities - current	$	(7,720	)		—	$	(7,720	)		—
Interest rate swap liabilities - noncurrent		(3,020	)		—		(3,020	)		—
Commodity derivative assets - current		148			—		148			—
Commodity derivative assets - noncurrent		6			—		6			—
Commodity derivative liabilities - current		(5,710	)		—		(5,710	)		—
Commodity derivative liabilities - noncurrent		(1,230	)		—		(1,230	)		—

Total	$	(17,526	)	$	—	$	(17,526	)	$	—


				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 costless collars and swap derivative contracts to hedge against the variability in the fractionation, or 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 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 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 September 30, 2010:


	Average Volume Per Day			Swap Price			Weighted Average Price					Fair Value at September 30, 2010
	Average Volume Per Day			Swap Price			Put			Call		Fair Value at September 30, 2010
												(in thousands)
Crude oil collar		(barrels	)					(per barrel	)
Fourth quarter 2010		750					$	70.00		$	81.25	$	(177	)

Crude oil collar		(barrels	)					(per barrel	)
Fourth quarter 2010		1,000					$	68.00		$	80.00	$	(309	)

Natural gas purchase swap		(MMBtu	)		(MMBtu	)
Fourth quarter 2010		7,100		$	5.885							$	(1,264	)

NGL - natural gasoline collar		(gallons	)					(per gallon	)
Fourth quarter 2010		42,000					$	1.55		$	2.03	$	(25	)

NGL - natural gasoline collar		(gallons	)					(per gallon	)
First quarter 2011 through fourth quarter 2011		95,000					$	1.57		$	1.94	$	(2,020	)

Crude oil collar		(barrels	)					(per barrel	)
First quarter 2011 through fourth quarter 2011		400					$	75.00		$	98.50	$	155

Natural gas purchase swap		(MMBtu	)		(MMBtu	)
First quarter 2011 through fourth quarter 2011		6,500		$	5.796							$	(3,146	)

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 (in millions)		Swap Interest Rates (1)					Fair Value September 30, 2010
Term	Notional Amounts (in millions)		Pay			Receive		Fair Value September 30, 2010
March 2010 - December 2011	$	250.0		3.37	%		LIBOR	$	(9,522	)
December 2011 - December 2012	$	100.0		2.09	%		LIBOR	$	(1,218	)

(1)	References to LIBOR represent the 3-month rate.

We reported a (i) net derivative liability of $10.7 million at September 30, 2010 and (ii) gain in accumulated other comprehensive income (“AOCI”) of $0.1 million as of September 30, 2010 related to the Interest Rate Swaps. In connection with periodic settlements, we reclassified a total of $1.1 million and $0.4 million of net hedging losses on the Interest Rate Swaps from AOCI to interest expense and derivatives, respectively, during the nine months ended September 30, 2010. See the following “Financial Statement Impact of Derivatives” section for the impact of the Interest Rate Swaps on our 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 Consolidated Statements of Income for the periods presented:


	Location of gain (loss) on derivatives recognized in income	Three Months Ended September 30,						Nine Months Ended September 30,
		2010			2009			2010			2009
Derivatives not designated as hedging instruments:
Interest rate contracts (1)	Interest expense		—			(857	)		(1,090	)		(2,600	)
Interest rate contracts	Derivatives		(2,568	)		(3,947	)		(7,739	)		(3,251	)
Commodity contracts	Derivatives		(8,452	)		1,137			(3,775	)		(8,754	)

Total decrease in net income resulting from derivatives		$	(11,020	)	$	(3,667	)	$	(12,604	)	$	(14,605	)

Realized and unrealized derivative impact:
Cash received (paid) for commodity and interest rate contract settlements	Derivatives		(2,435	)		(314	)		(6,493	)		4,135
Cash paid for interest rate contract settlements	Interest expense		—			—			—			(370	)
Unrealized derivative losses (2)			(8,585	)		(3,353	)		(6,111	)		(18,370	)

Total decrease in net income resulting from derivatives		$	(11,020	)	$	(3,667	)	$	(12,604	)	$	(14,605	)

(1)	This activity represents Interest Rate Swap amounts reclassified out of AOCI and into earnings.

(2)	This activity represents unrealized losses in the interest expense and derivatives caption on our 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 Consolidated Balance Sheets for the periods presented:


		Fair values as of September 30, 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	$	—	$	7,720	$	—	$	7,710
Interest rate contracts	Derivative assets/liabilities - noncurrent		—		3,020		1,266		3,241
Commodity contracts	Derivative assets/liabilities - current		148		5,710		1,331		3,541
Commodity contracts	Derivative assets/liabilities - noncurrent		6		1,230		18		1,044

Total derivatives not designated as hedging instruments		$	154	$	17,680	$	2,615	$	15,536

Total fair value of derivative instruments		$	154	$	17,680	$	2,615	$	15,536

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

As of September 30, 2010, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of September 30, 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 $6.5 million and $4.6 million for the nine months ended September 30, 2010 and 2009, with a corresponding increase in the investment. The joint ventures generally pay quarterly distributions on their cash flow. We received distributions of $9.0 million and $2.1 million for the nine months ended September 30, 2010 and 2009. Equity earnings related to our 50% interest in Coal Handling Solutions LLC are included in coal services revenues, and equity earnings related to our 25% interest in Thunder Creek and our 50% interest in Crosspoint are recorded in other revenues on the Consolidated Statements of Income. The equity investments for all joint ventures are included in the equity investments caption on the Consolidated Balance Sheets.

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


	September 30, 2010		December 31, 2009
Current assets	$	38,535	$	32,996
Noncurrent assets	$	206,920	$	214,463
Current liabilities	$	7,674	$	4,898
Noncurrent liabilities	$	5,636	$	5,392

	Nine Months Ended September 30,
	2010		2009
Revenues	$	52,722	$	46,514
Expenses	$	25,438	$	26,616
Net income	$	27,284	$	19,898

6.	Long-term Debt

Revolver

On August 13, 2010, we entered into an amended and restated secured credit agreement (the “Revolver”) increasing our borrowing capacity under the Revolver to $850 million. As of September 30, 2010, net of outstanding indebtedness of $365.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $483.4 million on the Revolver. The Revolver matures August 13, 2015. The Revolver includes a $10 million sublimit for the issuance of letters of credit and a $25 million sublimit for swingline borrowings. We have an option, upon receipt of commitments from one or more lenders, to increase the commitments under the Revolver by up to an additional $200 million, to a total of $1.05 billion. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at the base rate plus an applicable margin ranging from 1.25% to 2.25% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 2.25% to 3.25% if we select the LIBOR-based indebtedness option.

The Revolver contains customary affirmative and negative covenants. It requires that we abide by certain financial covenants, as follows: (i) a ratio of not more than 5.25 to 1.00 of Consolidated Total Indebtedness (as defined in the Revolver) to Consolidated EBITDA (as defined in the Revolver) for each of the four most recently completed fiscal quarters; (ii) a ratio of not more than 3.75 to 1.00 of Consolidated Secured Indebtedness (as defined in the Revolver) to Consolidated EBITDA for each of the four most recently completed fiscal quarters; and (iii) a ratio of at least 2.50 to 1.00 of Consolidated EBITDA to Consolidated Interest Expense (as defined in the Revolver) for each of the four most recently completed fiscal quarters. Each ratio is calculated as of the end of each fiscal quarter.

Senior Notes

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 underwriter fees and expenses of approximately $7.4 million, were used to repay borrowings under the Revolver. The Senior Notes are senior to any subordinated indebtedness and are effectively subordinated to all of our secured indebtedness, including our indebtedness under the 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 the Revolver.

7.	Partners’ Capital and Distributions

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 and nine months ended September 30, 2010, average awards of 12,000 and 135,000 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. For the three and nine months ended September 30, 2009, average awards of 105,000 and 112,000 were excluded.

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


	Three Months Ended September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Net income	$	10,774		$	18,824		$	48,685		$	41,614
Adjustments:
Distributions payable on account of incentive distribution rights		(6,093	)		(6,035	)		(18,232	)		(18,105	)
Distributions payable on account of general partner interest		(502	)		(497	)		(1,502	)		(1,491	)
General partner interest in excess of distributions over earnings allocable to the general partner interest		408			241			892			1,020

Net income allocable to limited partners and participating securities	$	4,587		$	12,533		$	29,843		$	23,038
Adjustments:
Distributions to participating securities		(32	)		(166	)		(389	)		(501	)
Participating securities’ allocable share of net income		26			(83	)		233			(152	)

Net income allocable to limited partners	$	4,581		$	12,284		$	29,687		$	22,385


Weighted average limited partner units, basic and diluted		52,293			51,799			52,034			51,799

Net income per limited partner unit, basic and diluted	$	0.09		$	0.24		$	0.57		$	0.43

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.

The following table reflects the allocation of total cash distributions paid by us during the periods presented:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Limited partner units	$	24,578	$	24,346	$	73,313	$	73,037
General partner interest (2%)		501		497		1,496		1,491
Incentive distribution rights		6,093		6,035		18,174		18,105
Phantom units		33		333		406		333

Total cash distributions paid	$	31,205	$	31,211	$	93,389	$	92,966


Total cash distributions paid per limited partner unit	$	0.47	$	0.47	$	1.41	$	1.41

On November 12, 2010, we will pay a $0.47 per unit quarterly distribution to unitholders of record on November 8, 2010. This per unit distribution remains unchanged from the previous distribution paid on August 13, 2010.

8.	Related-Party Transactions

In June 2010, Penn Virginia Corporation (“PVA”) sold its remaining interest in PVG and as a result, PVA no longer owns any limited or general partner interests in us or PVG. As a result of the divestiture, the related party transactions noted below are now considered arm’s-length and no longer require separate disclosures. PVA and PVG executed a transition agreement covering the services of certain shared employees, aiding the transition of corporate and accounting functions that could continue until March 2011. Related party transactions included charges from PVA for certain corporate administrative expenses which are allocable to us and our subsidiaries. Other transactions involved subsidiaries of PVA related to the marketing of natural gas, gathering and processing of natural gas, and the purchase and sale of natural gas and NGLs in which we took title to the products. The Consolidated Statements of Income and Consolidated Balance Sheet amounts noted below represent related party transactions through June 7, 2010 (date of divestiture). Future periodic disclosure of amounts will be historical in nature.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Consolidated Statements of Income:
Natural gas midstream revenues	$	—	$	16,221	$	29,002	$	59,585
Other income	$	—	$	298	$	787	$	1,069
Cost of gas purchased	$	—	$	15,147	$	27,780	$	56,376
General and administrative	$	—	$	1,550	$	1,773	$	4,650

	September 30, 2010		December 31, 2009
Consolidated Balance Sheets:
Accounts receivable	$	—	$	674
Accounts payable	$	—	$	7,889

9.	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. 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 generally 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 Consolidated Statements of Income. Through September 30, 2010, we granted 232,819 phantom units at a weighted average grant-date fair value of $22.85.

Because PVA’s divestiture of PVG was considered a change of control under the LTIP, all unvested restricted and phantom units granted to employees performing services for the benefit of us were considered vested on the date of the divestiture. In total, 400,090 phantom units vested and an equal number of new common units were issued on that date. The restrictions on approximately 36,000 restricted units were also lifted. In connection with the normal three-year vesting and this accelerated vesting of phantom and restricted units, we recognized non-cash compensation expense of $0.1 million and $7.2 million for the three and nine months ended September 30, 2010. We also recognized a total of $0.3 million and $0.5 million compensation expense for the three and nine months ended September 30, 2010 related to the granting of deferred common units under our LTIP. Compensation expense of $1.1 million and $3.9 million was recognized for the three and nine months ended September 30, 2009 related to the vesting of restricted, phantom and deferred common units under the LTIP.

10.

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 September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
Net income	$	10,774	$	18,824	$	48,685	$	41,614
Unrealized holding losses on derivative activities		—		—		—		(506	)
Reclassification adjustment for derivative activities		414		857		1,504		2,600

Comprehensive income	$	11,188	$	19,681	$	50,189	$	43,708

11.

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.

On September 27, 2010, a putative class action complaint was filed by a purported Penn Virginia GP Holdings, L.P. (“PVG”) unitholder against PVG; PVG GP, LLC (“PVG GP”); the Partnership; Penn Virginia Resource GP, LLC (“Partnership GP”); PVR Radnor, LLC (“MergerCo”) and PVG GP’s directors in the Court of Chancery of the State of Delaware under the captionIsrani v. Penn Virginia GP Holdings, L.P., et al., civil action no. 5851-CC. The complaint alleges that certain of the defendants breached their fiduciary duties to PVG’s public unitholders in connection with the Merger by, among other things, accepting insufficient consideration and that the Partnership, the Partnership GP and MergerCo aided and abetted those breaches. Among other things, the complaint seeks an order: certifying a class consisting of all PVG public unitholders, preliminarily and permanently enjoining the consummation of the Merger, in the event the Merger is consummated, rescinding the Merger or awarding rescissory damages in an unspecified amount, directing defendants to account for the alleged damages sustained by PVG unitholders, and an award of attorneys’ fees and costs.

On September 29, 2010, a putative class action complaint was filed by a purported PVG unitholder against PVG, PVG GP, the Partnership, the Partnership GP, MergerCo and PVG GP’s directors and a PVG GP officer in the Court of Chancery of the State of Delaware under the captionRooney v. Penn Virginia GP Holdings, L.P., et al., civil action no. 5859-CC. The complaint alleges that certain of the defendants breached their fiduciary duties to PVG’s public unitholders in connection with the Merger by, among other things, accepting insufficient consideration and agreeing to preclusive deal protection devices and that the Partnership, the Partnership GP and PVG GP aided and abetted those breaches. Among other things, the complaint seeks an order: certifying a class consisting of all PVG public unitholders, enjoining the consummation of the Merger, to the extent already implemented, rescinding the Merger or awarding rescissory damages in an unspecified amount, directing certain defendants to account for damages suffered by PVG unitholders, and an award of attorneys’ fees and costs.

On October 7, 2010, the Court of Chancery of the State of Delaware entered a stipulation and order consolidating the two actions described above under the captionIn re Penn Virginia GP Holdings, L.P. Shareholder Litigation, C.A. No. 5851-CC, and designating the complaint filed in civil action no. 5851-CC as the operative complaint. Neither we nor the other defendants have yet answered or otherwise responded to the complaint in the consolidated action.

On October 1, 2010, a putative class action complaint was filed by a purported PVG unitholder against PVG, the Partnership and certain of PVG GP’s directors in the Court of Common Pleas of Delaware County, Pennsylvania under the captionEpoch v. Penn Virginia GP Holdings, L.P., et al.In the complaint, the plaintiff alleges that certain of the defendants breached their fiduciary duties to PVG’s public unitholders in connection with the Merger by, among other things, accepting insufficient consideration and engaging in a flawed process and that certain of the defendants aided and abetted those breaches. Among other things, the complaint seeks an order certifying a class consisting of

all PVG public unitholders, enjoining the consummation of the Merger, rescinding the Merger, directing the board of directors of PVG GP to obtain a transaction that is in the best interests of the PVG unitholders and an award of attorneys’ fees and costs. Neither we nor the other defendants have yet answered or otherwise responded to the complaint.

On October 6, 2010, a putative class action complaint was filed by a purported PVG unitholder against PVG, PVG GP, the Partnership, the Partnership GP, MergerCo and certain of PVG GP’s officers and directors in the Court of Common Pleas of Delaware County, Pennsylvania under the captionScheifele v. Shea, et al.In the complaint, the plaintiff alleges that certain of the defendants breached their fiduciary duties to PVG’s public unitholders in connection with the Merger by, among other things, means of an unfair process and an unfair price and that certain of the defendants aided and abetted those breaches. Among other things, the complaint seeks an order certifying a class consisting of all PVG public unitholders, enjoining the Merger preliminarily or permanently, rescinding the Merger, awarding damages and awarding attorneys’ fees and costs. Neither we nor the other defendants have yet answered or otherwise responded to the complaint.

Environmental Compliance

As of September 30, 2010 and December 31, 2009, our environmental liabilities were $0.9 million and $1.0 million, which represents our best estimate of the liabilities as of those dates. 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 nine months ended September 30, 2010, two of our natural gas midstream segment customers accounted for $86.5 million and $71.2 million, or 14% and 12%, of our total consolidated revenues. At September 30, 2010, 23% of our consolidated accounts receivable related to these customers.

12.

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. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities and collecting oil and gas royalties.

•

Natural Gas Midstream — Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. In addition, we own member interests in joint ventures that gather and transport natural gas.

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


	Revenues				Operating income
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010			2009
Coal and natural resource management	$	40,408	$	35,179	$	26,374		$	21,225
Natural gas midstream		182,421		120,446		5,956			6,591

Consolidated totals	$	222,829	$	155,625	$	32,330		$	27,816

Interest expense						(10,639	)		(6,505	)
Other						103			323
Derivatives						(11,020	)		(2,810	)

Consolidated net income					$	10,774		$	18,824


	Additions to property and equipment				Depreciation, depletion & amortization
	Three Months Ended September 30,				Three Months Ended September 30,
	2010		2009		2010			2009
Coal and natural resource management	$	169	$	140	$	7,440		$	7,999
Natural gas midstream		33,077		39,031		11,262			9,852

Consolidated totals	$	33,246	$	39,171	$	18,702		$	17,851


	Revenues				Operating income
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010			2009
Coal and natural resource management	$	114,550	$	108,575	$	71,516		$	66,532
Natural gas midstream		504,189		353,228		13,436			4,604

Consolidated totals	$	618,739	$	461,803	$	84,952		$	71,136

Interest expense						(25,368	)		(18,486	)
Other						615			969
Derivatives						(11,514	)		(12,005	)

Consolidated net income					$	48,685		$	41,614


	Additions to property and equipment				Depreciation, depletion & amortization
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010			2009
Coal and natural resource management	$	18,283	$	2,046	$	22,145		$	23,557
Natural gas midstream		57,560		71,245		32,638			28,414

Consolidated totals	$	75,843	$	73,291	$	54,783		$	51,971


	Total assets at
	September 30, 2010		December 31, 2009
Coal and natural resource management	$	586,957	$	574,258
Natural gas midstream		662,062		633,802

Consolidated totals	$	1,249,019	$	1,208,060

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 our Annual Report on Form 10-K for the year ended December 31, 2009 and our

most recent quarterly report on Form 10-Q for the quarter ended June 30, 2010.

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 and our most recent quarterly report on Form 10-Q for the quarter ended June 30, 2010. 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 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 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 September 30, 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:

Merger

Pursuant to the Merger Agreement, PVG agreed to support the Merger by, among other things, voting its Partnership common units in favor of the Merger and against any transaction that, among other things, would materially delay or prevent the consummation of the Merger. The agreement to support automatically terminates if the conflicts committee of the board of directors or the board of directors of the general partner of PVG changes its recommendation to PVG’s unitholders with respect to the Merger or the conflicts committee of the board of directors or the board of directors of our general partner changes its recommendation to the Partnership’s unitholders with respect to the Merger.

respect to the issuance of our common units in connection with the Merger, (v) receipt of certain tax opinions, (vi) approval for listing our common units to be issued in connection with the Merger on the New York Stock Exchange and (vii) the execution of our Fourth Amended and Restated Agreement of Limited Partnership.

2010 Commodity Prices

Coal royalties, which accounted for 87% of the coal and natural resource management segment revenues for the three months ended September 30, 2010 and 85% for the same period in 2009, were higher as compared to 2009. The increase was attributed to increased production and higher realized coal royalty per ton primarily by the Central Appalachian region. The metallurgical market remains the driver behind this increase. We also continue to benefit from long-term contract prices our lessees previously negotiated with their customers.

With the exception of natural gas prices, which increased, the average commodity prices for crude oil and natural gas liquids, or NGLs, for the third quarter of 2010 decreased from levels experienced in the second quarter of 2010. However, all commodity prices increased for the nine months ended September 30, 2010 compared to the same period of 2009.

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 56% and 54% 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 Marcellus Shale Construction

Construction efforts continue in Pennsylvania as we work toward building and operating gas gathering pipelines and compression facilities servicing natural gas producers in the Marcellus Shale development. The Wyoming county project became operational during June, while projects targeting parts of Lycoming, Tioga and Bradford counties in central Pennsylvania have moved forward.

Revolver Amendment

On August 13, 2010, we entered into an amended and restated secured credit agreement (the “Revolver”) increasing our borrowing capacity under the Revolver to $850 million. As of September 30, 2010, net of outstanding indebtedness of $365.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $483.4 million on the Revolver. The Revolver matures August 13, 2015. The Revolver includes a $10 million sublimit for the issuance of letters of credit and a $25 million sublimit for swingline borrowings. We have an option, upon the receipt of commitments from one or more lenders, to increase the commitments under the Revolver by up to an additional $200 million, to a total of $1.05 billion. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at base rate plus an applicable margin ranging from 1.25% to 2.25% if we select the base rate indebtedness option under the

Revolver or at a rate derived from LIBOR plus and applicable margin ranging from 2.25% to 3.25% if we select the LIBOR-based indebtedness option.

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 the Revolver and proceeds from equity offerings. As discussed in more detail in “—Sources of Liquidity” below, as of September 30, 2010, we had availability of $483.4 million on the Revolver. 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 statements of cash flow for the periods presented:


	Nine Months Ended September 30,
	2010			2009
Cash flows from operating activities:
Net income	$	48,685		$	41,614
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		72,933			71,602
Net changes in operating assets and liabilities		25,196			3,209

Net cash provided by operating activities		146,814			116,425
Net cash used in investing activities		(74,858	)		(72,419	)
Net cash used in financing activities		(67,484	)		(42,224	)

Net increase in cash and cash equivalents	$	4,472		$	1,782

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the nine months ended September 30, 2010 as compared to the same period in 2009 was driven by an increase in the natural gas midstream segment’s gross margin and higher coal and natural resource management revenues due to higher realized royalty per ton. These increases were offset by increased derivative settlements paid.

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, including accruals, for the periods presented:


	Nine Months Ended September 30,
	2010		2009
Coal and natural resource management
Acquisitions	$	17,870	$	1,996
Other property and equipment expenditures		484		50

Total		18,354		2,046


Natural gas midstream
Expansion capital expenditures		53,011		59,403
Other property and equipment expenditures		9,873		6,067

Total		62,884		65,470


Total capital expenditures	$	81,238	$	67,516

Our capital expenditures for the nine months ended September 30, 2010 and 2009 consisted primarily of natural gas midstream expansion capital used to increase our operational footprint in our Panhandle and Marcellus Shale systems. The coal and natural resource management segment acquired 10 million tons of coal in Northern Appalachia for $17.7 million.

Cash Flows From Financing Activities

During the nine months ended September 30, 2010, we incurred $19.0 million of debt issuance costs related to the issuance of the $300 million Senior Notes and for the amended and restated Revolver. The net borrowings during both the nine months ended September 30, 2010 and 2009 were used to finance acquisition and expansion projects.

Certain Non-GAAP Financial Measures

We use non-GAAP (Generally Accepted Accounting Principles) 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 September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Reconciliation of GAAP “Net income” to Non-GAAP “Distributable cash flow”
Net income	$	10,774		$	18,824		$	48,685		$	41,614
Depreciation, depletion and amortization		18,702			17,851			54,783			51,971
Commodity derivative contracts:
Derivative losses included in net income		11,020			3,667			12,604			14,235
Cash receipts (payments) to settle derivatives for the period		(2,435	)		(314	)		(6,493	)		4,135
Equity earnings from joint venture, net of distributions		110			(1,385	)		2,500			(2,456	)
Maintenance capital expenditures		(4,246	)		(1,430	)		(10,357	)		(6,067	)


Distributable cash flow (a)	$	33,925		$	37,213		$	101,722		$	103,432


Distribution to Partners:

Limited partner units	$	24,578		$	24,346		$	73,313		$	73,037
Phantom units (b)		33			333			406			333
General partner interest		501			497			1,496			1,491
Incentive distribution rights (c)		6,093			6,035			18,174			18,105


Total cash distribution paid during period	$	31,205		$	31,211		$	93,389		$	92,966


Total cash distribution paid per unit during period	$	0.47		$	0.47		$	1.41		$	1.41


Reconciliation of GAAP “Net income” to Non-GAAP “Net income as adjusted”
Net income	$	10,774		$	18,824		$	48,685		$	41,614
Adjustments for derivatives:
Derivative losses included in net income		11,020			3,667			12,604			14,235
Cash receipts (payments) to settle derivatives for the period		(2,435	)		(314	)		(6,493	)		4,135


Net income, as adjusted (d)	$	19,359		$	22,177		$	54,796		$	59,984


Allocation of net income, as adjusted:
General partner’s interest in net income, as adjusted	$	6,359		$	6,358		$	18,964		$	18,943
Limited partners’ interest in net income, as adjusted	$	13,000		$	15,819		$	35,832		$	41,041

Net income, as adjusted, per limited partner unit, basic and diluted	$	0.25		$	0.30		$	0.69		$	0.78

(a)

Distributable cash flow represents net income plus depreciation, depletion and amortization (“DD&A”) expenses, plus (minus) derivative losses (gains) included in 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 2010 and 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 third quarter of 2010 of $33.9 million was $3.3 million, or nine percent lower, than the $37.2 million of distributable cash flow in the third quarter of 2009 primarily due to:

•

$4.1 million increase in interest expense associated with the higher interest bearing Senior Notes; and

•

$2.1 million increase in cash payments to settle derivatives; and

•

$2.8 million increase in maintenance capital

These decreases in distributable cash flow were partially offset by:

•

$5.4 million increase in operating income adjusted for DD&A for both the coal and midstream segments, due to increased average coal royalties per ton and increased natural gas processing margins.

Sources of Liquidity

Long-Term Debt

Revolver. On August 13, 2010, we entered into an amended and restated secured credit agreement (the “Revolver”) increasing our borrowing capacity under the Revolver to $850 million. As of September 30, 2010, net of outstanding indebtedness of $365.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $483.4 million on the Revolver. The Revolver matures August 13, 2015. The Revolver includes a $10 million sublimit for the issuance of letters of credit and a $25 million sublimit for swingline borrowings. We have an option, upon receipt of commitments from one or more lenders, to increase the commitments under the Revolver by up to an additional $200 million, to a total of $1.05 billion. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at base rate plus an applicable margin ranging from 1.25% to 2.25% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus and applicable margin ranging from 2.25% to 3.25% if we select the LIBOR-based indebtedness option. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2010 was approximately 2.4%. We do not have a public rating for the Revolver. As of September 30, 2010, we were in compliance with all of our covenants under the Revolver.

Senior Notes.In April 2010, we sold $300.0 million of 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 the Revolver. The Senior Notes are senior to any subordinated indebtedness, and are effectively subordinated to all of our secured indebtedness including the

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 the Revolver.

Interest Rate Swaps.We have entered into interest rate swaps, or the 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 September 30, 2010:


	Notional Amounts (in millions)		Swap Interest Rates (1)
Term	Notional Amounts (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.

After considering the applicable margin of 2.50% in effect as of September 30, 2010 the total interest rate on the $250.0 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.87% as of September 30, 2010.

Future Capital Needs and Commitments

As of September 30, 2010, our remaining borrowing capacity under the Revolver of approximately $483.4 million is sufficient to meet our anticipated 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 $134.0 million, including anticipated maintenance capital of $15.0 million to $17.5 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 the Revolver. Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by operating cash flows, borrowings under the Revolver and 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 September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Revenues	$	222,829		$	155,625		$	618,739		$	461,803
Expenses		190,499			127,809			533,787			390,667

Operating income		32,330			27,816			84,952			71,136
Other income (expense)		(21,556	)		(8,992	)		(36,267	)		(29,522	)

Net income	$	10,774		$	18,824		$	48,685		$	41,614

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 Nine Months Ended September 30, 2010:
Revenues	$	114,550		$	504,189		$	618,739
Cost of gas purchased		—			(415,111	)		(415,111	)
Operating costs and expenses		(20,889	)		(43,004	)		(63,893	)
Depreciation, depletion and amortization		(22,145	)		(32,638	)		(54,783	)

Operating income	$	71,516		$	13,436		$	84,952


For the Nine Months Ended September 30, 2009:
Revenues	$	108,575		$	353,228		$	461,803
Cost of gas purchased		—			(285,129	)		(285,129	)
Operating costs and expenses		(18,486	)		(35,081	)		(53,567	)
Depreciation, depletion and amortization		(23,557	)		(28,414	)		(51,971	)

Operating income	$	66,532		$	4,604		$	71,136

Coal and Natural Resource Management Segment

Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 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 September 30,				Favorable (Unfavorable)			% Change
	2010		2009		Favorable (Unfavorable)			% Change
Financial Highlights
Revenues
Coal royalties	$	34,983	$	29,821	$	5,162			17	%
Coal services		1,975		1,869		106			6	%
Timber		1,437		1,582		(145	)		(9	%)
Oil and gas royalty		631		535		96			18	%
Other		1,382		1,372		10			1	%

Total revenues		40,408		35,179		5,229			15	%


Expenses
Operating		2,908		2,435		(473	)		(19	%)
General and administrative		3,686		3,520		(166	)		(5	%)
Depreciation, depletion and amortization		7,440		7,999		559			7	%

Total expenses		14,034		13,954		(80	)		(1	%)


Operating income	$	26,374	$	21,225	$	5,149			24	%


Other data

Coal royalty tons by region
Central Appalachia		4,805		4,594		211			5	%
Northern Appalachia		828		563		265			47	%
Illinois Basin		987		1,333		(346	)		(26	%)
San Juan Basin		1,910		1,897		13			1	%

Total tons		8,530		8,387		143			2	%


Coal royalties revenues by region
Central Appalachia	$	25,868	$	21,089	$	4,779			23	%
Northern Appalachia		2,177		1,065		1,112			104	%
Illinois Basin		2,756		3,644		(888	)		(24	%)
San Juan Basin		4,182		4,023		159			4	%

Total royalties	$	34,983	$	29,821	$	5,162			17	%


Coal royalties per ton by region ($/ton)
Central Appalachia	$	5.38	$	4.59	$	0.79			17	%
Northern Appalachia		2.63		1.89		0.74			39	%
Illinois Basin		2.79		2.73		0.06			2	%
San Juan Basin		2.19		2.12		0.07			3	%

Average royalties per ton	$	4.10	$	3.56	$	0.54			15	%

Revenues

Coal royalties revenues increased due to higher realized coal royalties per ton. Metallurgical coal is in high demand, driving up the price realized for metallurgical coal sales by our lessees in Central Appalachia.

Coal production increased slightly in the current period. The increase in the Central Appalachia was driven by the metallurgical coal market and lessees trying to meet the demand. The increase in Northern Appalachia is due to

the timing of longwall operations on our property. These increases were offset by a decrease in production in the Illinois Basin. Poor mining conditions have lowered production in this region.

Expenses

Given the timing of certain operating costs (such as coal royalties paid, core hole drilling, etc.), operating expenses were higher in the third quarter of 2010 compared to the same quarter of 2009.

DD&A expenses decreased for the comparative periods due to lower levels of timber harvesting.

Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 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:


	Nine Months Ended September 30,				Favorable (Unfavorable)			% Change
	2010		2009		Favorable (Unfavorable)			% Change
Financial Highlights
Revenues
Coal royalties	$	98,088	$	90,448	$	7,640			8	%
Coal services		5,976		5,502		474			9	%
Timber		4,488		4,355		133			3	%
Oil and gas royalty		2,000		1,783		217			12	%
Other		3,998		6,487		(2,489	)		(38	%)

Total revenues		114,550		108,575		5,975			6	%


Expenses
Operating		7,670		7,211		(459	)		(6	%)
General and administrative		13,219		11,275		(1,944	)		(17	%)
Depreciation, depletion and amortization		22,145		23,557		1,412			6	%

Total expenses		43,034		42,043		(991	)		(2	%)


Operating income	$	71,516	$	66,532	$	4,984			7	%


Other data

Coal royalty tons by region
Central Appalachia		13,746		13,902		(156	)		(1	%)
Northern Appalachia		2,935		2,680		255			10	%
Illinois Basin		3,176		3,739		(563	)		(15	%)
San Juan Basin		5,788		5,553		235			4	%

Total tons		25,645		25,874		(229	)		(1	%)


Coal royalties revenues by region
Central Appalachia	$	70,592	$	63,964	$	6,628			10	%
Northern Appalachia		6,137		4,965		1,172			24	%
Illinois Basin		8,685		9,747		(1,062	)		(11	%)
San Juan Basin		12,674		11,772		902			8	%

Total royalties	$	98,088	$	90,448	$	7,640			8	%


Coal royalties per ton by region ($/ton)
Central Appalachia	$	5.14	$	4.60	$	0.54			12	%
Northern Appalachia		2.09		1.85		0.24			13	%
Illinois Basin		2.73		2.61		0.12			5	%
San Juan Basin		2.19		2.12		0.07			3	%

Average royalties per ton	$	3.82	$	3.50	$	0.32			9	%

Revenues

Coal production slightly 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 and market conditions. The Northern Appalachia region benefited from the timing of longwall operations on our property.

Other revenues 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

Given the timing of certain operating costs (such as coal royalties paid, core hole drilling, etc.), operating expenses were higher in 2010 compared to the same period of 2009.

General and administrative expense increased due to the accelerated vesting of equity compensation. PVA divested its interest in PVG during 2009 and 2010 and no longer owns any limited or general partner interests in PVR. Because the divestiture was considered a change of control under our long-term incentive plan, all unvested restricted and phantom units granted to employees performing services for the benefit of PVR were considered vested on the date the last PVG units were sold, June 7, 2010. In conjunction with the separation from PVA, we have incurred additional personnel and infrastructure costs, which have caused an increase in general and administrative expense.

DD&A expenses decreased for the comparative period due to lower levels of timber harvesting.

Natural Gas Midstream Segment

Three Months Ended September 30, 2010 Compared with Three Months Ended September 30, 2009

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 September 30,					Favorable (Unfavorable)			% Change
	2010			2009		Favorable (Unfavorable)			% Change
Financial Highlights
Revenues
Residue gas	$	98,534		$	62,801	$	35,733			57	%
Natural gas liquids		73,500			48,147		25,353			53	%
Condensate		4,814			4,659		155			3	%
Gathering, processing and transportation fees		3,359			2,836		523			18	%

Total natural gas midstream revenues (1)		180,207			118,443		61,764			52	%
Equity earnings in equity investment		1,639			1,597		42			3	%
Producer services		575			406		169			42	%

Total revenues		182,421			120,446		61,975			51	%


Expenses
Cost of gas purchased (1)		151,657			92,355		(59,302	)		(64	%)
Operating		8,840			7,401		(1,439	)		(19	%)
General and administrative		4,706			4,247		(459	)		(11	%)
Depreciation and amortization		11,262			9,852		(1,410	)		(14	%)

Total operating expenses		176,465			113,855		(62,610	)		(55	%)


Operating income	$	5,956		$	6,591	$	(635	)		(10	%)


Operating Statistics
System throughput volumes (MMcf)		36,233			29,811		6,422			22	%
Daily throughput volumes (MMcfd)		394			324		70			22	%

Gross margin	$	28,550		$	26,088	$	2,462			9	%
Cash impact of derivatives		(584	)		1,993		(2,577	)		(129	%)

Gross margin, adjusted for impact of derivatives	$	27,966		$	28,081	$	(115	)		(0	%)


Gross margin ($/Mcf)	$	0.79		$	0.88	$	(0.09	)		(10	%)
Cash impact of derivatives ($/Mcf)		(0.02	)		0.06		(0.08	)		(133	%)

Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.77		$	0.94	$	(0.17	)		(18	%)

(1)

For the three months ended September 30, 2009, we recorded $15.1 million of natural gas midstream revenues and $15.1 million for the cost of gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P (a subsidiary of PVA and considered a related party up to June 7, 2010) 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 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 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 system throughput and processed volumes, as well as higher commodity pricing and higher fractionation, or frac, spreads. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis. Offsetting the higher volumes and

commodity prices was a change in contract mix. We process gas under three general types of contracts (gas purchase/keep whole contracts, percentage-of-proceeds contracts, and fee-based arrangements). These contracts are more fully described in our Annual Report on Form 10-K for the year ended December 31, 2009. New gas volumes being added to our systems by producers are under percentage-of-proceeds contracts. The result of this is a relative decrease in gas purchase/keep whole contracts, meaning that we are sharing more of the processing margin with our producers. This translates into a lower unit margin realized on system volumes.

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 decreased by $0.17, or 18% percent as compared to the three months ended September 30, 2009. This decrease was moderately impacted by commodity derivatives as a result of higher commodity prices during the third quarter of 2010.

Expenses

Operating expenses increased due to prior and current years’ expansion projects and acquisitions. The related costs of these facilities include increased costs for compressor rentals, utilities and property tax.

In conjunction with the separation from PVA, we have incurred additional personnel and infrastructure costs, which have caused an increase in general and administrative expense.

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.

Nine Months Ended September 30, 2010 Compared with Nine Months Ended September 30, 2009

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:


	Nine Months Ended September 30,					Favorable (Unfavorable)			% Change
	2010			2009		Favorable (Unfavorable)			% Change
Financial Highlights
Revenues
Residue gas	$	270,763		$	211,165	$	59,598			28	%
Natural gas liquids		199,320			117,670		81,650			69	%
Condensate		17,863			11,507		6,356			55	%
Gathering, processing and transportation fees		9,416			8,540		876			10	%

Total natural gas midstream revenues (1)		497,362			348,882		148,480			43	%
Equity earnings in equity investment		4,919			3,345		1,574			47	%
Producer services		1,908			1,001		907			91	%

Total revenues		504,189			353,228		150,961			43	%

Expenses
Cost of gas purchased (1)		415,111			285,129		(129,982	)		(46	%)
Operating		24,647			22,085		(2,562	)		(12	%)
General and administrative		18,357			12,996		(5,361	)		(41	%)
Depreciation and amortization		32,638			28,414		(4,224	)		(15	%)

Total operating expenses		490,753			348,624		(142,129	)		(41	%)


Operating income	$	13,436		$	4,604	$	8,832			192	%


Operating Statistics
System throughput volumes (MMcf)		93,120			93,433		(313	)		(0	%)
Daily throughput volumes (MMcfd)		341			342		(1	)		(0	%)

Gross margin	$	82,251		$	63,753	$	18,498			29	%
Cash impact of derivatives		(225	)		9,162		(9,387	)		(102	%)

Gross margin, adjusted for impact of derivatives	$	82,026		$	72,915	$	9,111			12	%


Gross margin ($/Mcf)	$	0.88		$	0.68	$	0.20			29	%
Cash impact of derivatives ($/Mcf)		—			0.10		(0.10	)		(100	%)

Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.88		$	0.78	$	0.10			13	%

(1)

For the period of January 1 through June 7, 2010 and for the nine months ended September 30, 2009, we recorded $27.8 million and $56.4 million of natural gas midstream revenues and $27.8 million and $56.4 million for the cost of gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P (a subsidiary of PVA and considered a related party up to June 7, 2010) 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

The gross margin increase was a result of higher commodity pricing and higher frac spreads. System throughput volumes for the comparative periods were relatively flat. Offsetting the increased margins to some extent was a change in contract mix. As discussed previously, new gas being added to our systems by producers are done so primarily under percentage of proceeds contracts. The result of this is a relative decrease in gas purchase/keep whole contracts, meaning that we are sharing more of the processing margin with our producers.

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 $0.10, or 13% as compared to the nine months ended September 30, 2009. This favorable increase was moderately impacted by commodity derivatives as a result of higher commodity prices during 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

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 September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Operating income	$	32,330		$	27,816		$	84,952		$	71,136
Other income (expense)
Interest expense		(10,639	)		(6,505	)		(25,368	)		(18,486	)
Other		103			323			615			969
Derivatives		(11,020	)		(2,810	)		(11,514	)		(12,005	)

Net income	$	10,774		$	18,824		$	48,685		$	41,614

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


	Three Months Ended September 30,					Nine Months Ended September 30,
Source	2010			2009		2010			2009
Interest on Revolver	$	2,889		$	4,233	$	9,518		$	12,963
Interest on Senior Notes		6,188			—		10,588			—
Debt issuance costs and other		1,633			1,415		4,243			3,149
Interest rate swaps		—			857		1,090			2,600
Capitalized interest		(71	)		—		(71	)		(226	)

Total interest expense	$	10,639		$	6,505	$	25,368		$	18,486

Interest expense for the three and nine months ended September 30, 2010 has increased compared to the same periods in 2009. These increases are due to the issuance of the Senior Notes bearing an interest rate of 8.25% offset by lower levels of Revolver debt bearing interest at levels of 2.0% to 3.0% over the comparable period. Debt issuance costs have also increased related to Revolver changes in March 2009, the issuance of the Senior Notes in April 2010 and the amendment and restatement of the Revolver in August 2010.

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 September 30,						Nine Months Ended September 30,
	2010			2009			2010			2009
Interest Rate Swap unrealized derivative loss	$	(303	)	$	(1,640	)	$	(1,057	)	$	1,776
Interest Rate Swap realized derivative loss		(1,851	)		(2,307	)		(6,268	)		(5,027	)
Interest Rate Swap other comprehensive income reclass		(414	)		—			(414	)		—
Natural gas midstream commodity unrealized derivative loss		(7,868	)		(856	)		(3,550	)		(17,916	)
Natural gas midstream commodity realized derivative gain		(584	)		1,993			(225	)		9,162

Total derivative loss	$	(11,020	)	$	(2,810	)	$	(11,514	)	$	(12,005	)

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.

As of September 30, 2010 and December 31, 2009, our environmental liabilities were $0.9 million and $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.

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 September 30, 2010.

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 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 derivative financial instruments are significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

At September 30, 2010, we reported a net commodity derivative asset related to our natural gas midstream segment of $6.8 million that is with five counterparties and is substantially concentrated with two 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 and nine months ended September 30, 2010, we reported net derivative losses of $11.0 million and $11.5 million, respectively. 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 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 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 September 30, 2010:


	Average Volume Per Day			Swap Price			Weighted Average Price				Fair Value at September 30, 2010
	Average Volume Per Day			Swap Price			Put		Call		Fair Value at September 30, 2010
											(in thousands)

Crude oil collar		(barrels	)					(per barrel)
Fourth quarter 2010		750					$	70.00	$	81.25	$	(177	)

Crude oil collar		(barrels	)					(per barrel)
Fourth quarter 2010		1,000					$	68.00	$	80.00	$	(309	)

Natural gas purchase swap		(MMBtu	)		(MMBtu	)
Fourth quarter 2010		7,100		$	5.885						$	(1,264	)

NGL - natural gasoline collar		(gallons	)					(per gallon)
Fourth quarter 2010		42,000					$	1.55	$	2.03	$	(25	)

NGL - natural gasoline collar		(gallons	)					(per gallon)
First quarter 2011 through fourth quarter 2011		95,000					$	1.57	$	1.94	$	(2,020	)

Crude oil collar		(barrels	)					(per barrel)
First quarter 2011 through fourth quarter 2011		400					$	75.00	$	98.50	$	155

Natural gas purchase swap		(MMBtu	)		(MMBtu	)
First quarter 2011 through fourth quarter 2011		6,500		$	5.796						$	(3,146	)

											$	(6,786	)

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 $1.0 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 $0.8 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 $2.8 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 $2.8 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 $2.6 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 $2.4 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 $0.2 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 $1.4 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 September 30, 2010, we had $365.0 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 68% of our outstanding indebtedness under the Revolver as of September 30, 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 27% of our outstanding indebtedness under the Revolver as of September 30, 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 September 30, 2010 would cost us approximately $1.1 million in additional interest expense per year.

Customer Credit Risk

We are exposed to the credit risk of our natural gas midstream customers and coal lessees. For the nine months ended September 30, 2010, two of our natural gas midstream segment customers accounted for $86.5 million and $71.2 million, or 14% and 12%, of our total consolidated revenues. At September 30, 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 September 30, 2010, no receivables were collateralized, and we had a $0.2 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 September 30, 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 September 30, 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 I.

Legal Proceedings.

For information on legal proceedings, see Part I, Item I, Financial Statements, Note 11, “Commitments and Contingencies” in the Notes to Unaudited Consolidated Financial Statements included in this quarterly report, which is incorporated into this item by reference.

Item IA.

Risk Factors.

The following risk factors should be read in conjunction with the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2009 and most recent quarterly report on Form 10-Q for the quarter ended June 30, 2010. The risk factors listed below are updates or additional risk factors to consider.

Risks Related to the Merger

While the Merger Agreement is in effect, we may be limited in our ability to pursue other attractive business opportunities.

While the Merger Agreement is in effect, we have agreed to refrain from taking certain actions with respect to our businesses and financial affairs pending the consummation of the Merger or termination of the Merger Agreement. These restrictions could be in effect for an extended period of time if the consummation of the Merger is delayed. These limitations do not preclude us from conducting our business in the ordinary or usual course or from acquiring assets or businesses so long as such activity does not have a “material adverse effect” as such term is defined in the Merger Agreement or materially affect our ability to complete the transactions contemplated by the Merger Agreement.

In addition to the economic costs associated with pursuing the Merger, the management of our general partner will continue to devote substantial time and other human resources to the proposed Merger which could limit our ability to pursue other attractive business opportunities, including potential joint ventures, stand-alone projects and other transactions. If we are unable to pursue such other attractive business opportunities, our growth prospects and the long-term strategic position of our businesses following the Merger could be adversely affected.

Our existing unitholders will be diluted by the Merger.

The Merger will dilute the ownership position of our existing unitholders. Pursuant to the Merger Agreement, PVG unitholders will receive approximately 38.3 million of our limited partner common units as a result of the Merger. Immediately following the Merger, we will be owned approximately 46% by our current unitholders and approximately 54% by former PVG unitholders.

The number of our outstanding limited partner common units will increase as a result of the Merger, which could make it more difficult to pay the current level of quarterly distributions.

As of October 19, 2010, there were approximately 52.3 million of our limited partner common units outstanding. Pursuant to the Merger Agreement, we will issue, and PVG unitholders will receive, approximately 38.3 million of our limited partner common units. Accordingly, as a result of the Merger, the dollar amount required to pay the current per unit quarterly distributions will increase, which will increase the likelihood that we will not have sufficient funds to pay the current level of quarterly distributions to all of our unitholders. Using the amount of $0.47 per Partnership common unit paid on August 13, 2010 with respect to the second quarter of 2010, the aggregate cash distribution paid with respect to Partnership common units owned by our unitholders other than PVG totaled approximately $15.3 million. We distributed approximately $15.8 million to PVG for its approximately 19.6 million Partnership common units, the general partner interest in the Partnership and incentive distribution rights in the Partnership. Therefore, including distributions on phantom units of approximately $33,000, our combined total distribution paid with respect to the second quarter of 2010 was approximately $31.2 million. The combined pro

forma Partnership distribution with respect to the second quarter 2010, had the Merger been completed prior to such distribution, would result in $0.47 per unit being distributed on approximately 70.9 million Partnership common units, or a total of approximately $33.3 million, with the Partnership GP no longer receiving any distributions. Including distributions on phantom units of approximately $33,000, our combined pro forma distribution would be approximately $33.4 million. As a result, we would be required to distribute approximately an additional $2.2 million per quarter in order to maintain the distribution level of $0.47 per the Partnership Common Unit paid with respect to the second quarter of 2010.

Although the elimination of the incentive distribution rights may increase the cash available for distribution to our limited partner common units in the future, this source of funds may not be sufficient to meet the overall increase in cash required to maintain the current level of quarterly distributions to our unitholders.

Failure to complete the Merger or delays in completing the Merger could negatively impact our limited partner common unit price.

If the Merger is not completed for any reason, we may be subject to a number of material risks, including the following:

•

we will not realize the benefits expected from the Merger, including a potentially enhanced financial and competitive position;

•

the price of our limited partner common units may decline to the extent that the current market price of these securities reflects a market assumption that the Merger will be completed; and

•

some costs relating to the Merger, such as certain investment banking fees and legal and accounting fees, must be paid even if the Merger is not completed.

The costs of the Merger could adversely affect our operations and cash flows available for distribution to our unitholders.

We and PVG estimate the total costs of the Merger to be approximately $10.5 million, primarily consisting of investment banking, legal counsel, and accounting fees and financial printing and other related costs. These costs could adversely affect our operations and cash flows available for distributions to our unitholders. The foregoing estimate is preliminary and is subject to change.

Tax Risks Related to the Merger

No ruling has been obtained with respect to the U.S. federal income tax consequences of the Merger.

No ruling has been or will be requested from the IRS with respect to the U.S. federal income tax consequences of the Merger. Instead, we are relying on the opinion of our counsel, and PVG is relying on the opinion of counsel to its Conflicts Committee, as to the U.S. federal income tax consequences of the Merger to our unitholders and PVG unitholders, respectively. These opinions and positions may not be sustained if challenged by the IRS, which could result in a material change to the expected tax consequences of the Merger.

The intended U.S. federal income tax consequences of the Merger are dependent upon each of us and PVG being treated as a partnership for U.S. federal income tax purposes.

The treatment of the Merger as nontaxable to our unitholders and to PVG unitholders is dependent upon each of us and PVG being treated as a partnership for U.S. federal income tax purposes. If either we or PVG were treated as a corporation for U.S. federal income tax purposes, the consequences of the Merger would be materially different and the Merger would be treated as a taxable exchange in which gain or loss would be recognized by the PVG unitholders.

The U.S. federal income tax treatment of the Merger is subject to potential legislative changes and differing judicial or administrative interpretations.

The U.S. federal income tax consequences of the Merger depend on determinations of fact and interpretations of complex provisions of U.S. federal income tax law. The U.S. federal income tax rules are constantly under review by persons involved in the legislative process, the IRS and the U.S. Treasury Department, frequently resulting in revised interpretations of established concepts, statutory changes, revisions to Treasury Regulations and other modifications and interpretations. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could change the U.S. federal income tax treatment of the Merger to our unitholders and PVG’s unitholders. For example, the U.S. House of Representatives has passed legislation relating to the taxation of “carried interests” that may treat transactions, such as the Merger, occurring on or after an effective date of January 1, 2011, as a taxable exchange to a unitholder of a partnership such as PVG. The U.S. Senate has considered legislation that may have a similar effect. We and PVG are unable to predict whether this proposed legislation or any other proposals will ultimately be enacted, and if so, whether any such proposed legislation would be applied retroactively.

Tax Risks to Our Existing Unitholders

An existing unitholder of our limited partner common units may be required to recognize gain as a result of the Merger.

Although it is anticipated that for U.S. federal income tax purposes no gain or loss should be recognized by our existing unitholders solely as a result of the Merger, an existing unitholder may realize gain or loss resulting from (i) a decrease in such unitholder’s share of partnership liabilities pursuant to Section 752 of the Code, and (ii) amounts paid to or on behalf of us by another person pursuant to the Merger Agreement.

We estimate that the Merger will result in a relatively small increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our existing unitholders.

We estimate that the closing of the Merger will result in a relatively small increase in the amount of net income (or decrease in the amount of net loss) allocable to all of our existing unitholders. Although we have projected a maximum amount of such an impact for our existing unitholders, the actual amount and effect of such increase in net income (or decrease in net loss) for any Partnership unitholder may be more than anticipated because it will depend upon the unitholder’s particular situation, including when, and at what prices, the unitholder purchased our common units and the ability of the unitholder to utilize any suspended passive losses. In addition, the projections are based upon numerous assumptions, and the federal income tax liability of such unitholders could be further increased if we make a future offering of our common units and use the proceeds of the offering in a manner that does not produce substantial additional deductions, such as to repay indebtedness currently outstanding or to acquire property that is not eligible for depreciation or amortization for federal income tax purposes or that is depreciable or amortizable at a rate significantly slower than the rate currently applicable to our assets.

Item 6

Exhibits


2.1		Agreement and Plan of Merger, dated September 21, 2010, by and among Penn Virginia Resource Partners, L.P., Penn Virginia Resource GP, LLC, Penn Virginia GP Holdings, L.P., PVG GP LLC, and PVR Radnor, LLC (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on September 22, 2010).

10.1		Amended and Restated Credit Agreement, dated as of August 13, 2010 by and among PVR Finco LLC, the guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on August 19, 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: October 29, 2010	By:	/s/ Robert B. Wallace
		Robert B. Wallace
		Executive Vice President and Chief Financial Officer

Date: October 29, 2010	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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