Form 10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-Q 1 d241002d10q.htm FORM 10-Q Form 10-Q

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, 2011

¨	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)

(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 x 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 17, 2011, 70,981,867 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, 2011 and 2010		1

	Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010		2

	Consolidated Statements of Cash Flows for the Three and Nine Months Ended September 30, 2011 and 2010		3

	Consolidated Statements of Partners’ Capital and Comprehensive Income for the Nine Months Ended September 30, 2011 and 2010		4

	Notes to Consolidated Financial Statements		5

	Forward-Looking Statements		19

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		20

Item 3.	Quantitative and Qualitative Disclosures About Market Risk		37

Item 4.	Controls and Procedures		39

PART II.	Other Information

Item 1.	Legal Proceedings		40

Item 1A.	Risk Factors		40

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,
	2011			2010			2011			2010
Revenues
Natural gas midstream	$	259,710		$	180,207		$	722,898		$	497,362
Coal royalties		40,977			34,983			124,546			98,088
Other		7,665			7,639			24,757			23,289

Total revenues		308,352			222,829			872,201			618,739

Expenses
Cost of gas purchased		223,762			151,657			613,295			415,111
Operating		15,797			11,748			43,112			32,317
General and administrative		8,755			9,029			31,700			34,367
Depreciation, depletion and amortization		22,463			18,702			65,357			54,783

Total expenses		270,777			191,136			753,464			536,578

Operating income		37,575			31,693			118,737			82,161
Other income (expense)
Interest expense		(10,528	)		(10,639	)		(33,806	)		(25,368	)
Derivatives		8,690			(11,020	)		(6,289	)		(11,514	)
Other		120			111			384			654

Net income	$	35,857		$	10,145		$	79,026		$	45,933
Net loss (income) attributable to noncontrolling interests, pre-merger (Note 1)		—			(2,864	)		664			(18,671	)

Net income attributable to Penn Virginia Resource Partners, L.P.	$	35,857		$	7,281		$	79,690		$	27,262

Basic net income per limited partner unit	$	0.50		$	0.19		$	1.26		$	0.71
Diluted net income per limited partner unit	$	0.50		$	0.19		$	1.26		$	0.71
Weighted average number of units outstanding, basic and diluted		71,197			38,293			63,019			38,293

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, 2011			December 31, 2010
Assets
Current assets
Cash and cash equivalents	$	13,908		$	15,964
Accounts receivable, net of allowance for doubtful accounts		116,538			97,787
Derivative assets		1,381			—
Other current assets		5,449			5,900

Total current assets		137,276			119,651

Property, plant and equipment		1,555,924			1,295,227
Accumulated depreciation, depletion and amortization		(384,554	)		(324,181	)

Net property, plant and equipment		1,171,370			971,046

Equity investments		84,487			84,327
Intangible assets (net of accumulated amortization of $37,015 and $32,302)		72,237			76,950
Derivative assets		332			—
Other long-term assets		44,958			52,231

Total assets	$	1,510,660		$	1,304,205

Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	118,102		$	103,845
Deferred income		3,876			4,360
Derivative liabilities		11,527			19,516

Total current liabilities		133,505			127,721

Deferred income		9,646			7,874
Other liabilities		21,392			20,853
Derivative liabilities		1,255			5,107
Senior notes		300,000			300,000
Revolving credit facility		635,000			408,000
Partners’ capital
Common unitholders		409,087			213,646
Accumulated other comprehensive income		775			159

		409,862			213,805
Non-controlling interests, pre-merger (Note 1)		—			220,845

Total partners’ capital		409,862			434,650

Total liabilities and partners’ capital	$	1,510,660		$	1,304,205

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,
	2011			2010			2011			2010
Cash flows from operating activities
Net income	$	35,857		$	10,145		$	79,026		$	45,933
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		22,463			18,702			65,357			54,783
Commodity derivative contracts:
Total derivative losses (gains)		(8,690	)		11,020			6,289			12,604
Cash payments to settle derivatives		(6,699	)		(2,435	)		(19,477	)		(6,493	)
Non-cash interest expense		1,040			1,633			4,735			4,243
Non-cash unit-based compensation		966			137			2,805			6,024
Equity earnings, net of distributions received		2,818			110			4,635			2,500
Other		(127	)		(108	)		(909	)		(722	)
Changes in operating assets and liabilities
Accounts receivable		(2,766	)		(9,102	)		(18,729	)		1,828
Accounts payable and accrued liabilities		5,345			24,492			20,335			24,517
Deferred income		(855	)		4,695			(730	)		5,423
Other assets and liabilities		605			(8,850	)		(1,029	)		(9,809	)

Net cash provided by operating activities		49,957			50,439			142,308			140,831

Cash flows from investing activities
Acquisitions		(95	)		(6	)		(122,135	)		(17,870	)
Additions to property, plant and equipment		(67,000	)		(33,240	)		(141,796	)		(57,973	)
Other		347			315			2,558			985

Net cash used in investing activities		(66,748	)		(32,931	)		(261,373	)		(74,858	)

Cash flows from financing activities
Distributions to partners		(34,887	)		(30,619	)		(99,696	)		(91,403	)
Proceeds from issuance of senior notes		—			—			—			300,000
Proceeds from borrowings		60,000			44,000			252,000			110,000
Repayments of borrowings		(5,000	)		(25,490	)		(25,000	)		(365,100	)
Purchase of PVR limited partner units		—			—			—			(1,092	)
Cash paid for debt issuance costs		—			(10,430	)		(3,675	)		(19,177	)
Cash paid for merger		(16	)		—			(6,620	)		—

Net cash provided by (used in) financing activities		20,097			(22,539	)		117,009			(66,772	)

Net increase (decrease) in cash and cash equivalents		3,306			(5,031	)		(2,056	)		(799	)
Cash and cash equivalents – beginning of period		10,602			23,546			15,964			19,314

Cash and cash equivalents – end of period	$	13,908		$	18,515		$	13,908		$	18,515

Supplemental disclosure:
Cash paid for interest	$	5,941		$	3,931		$	29,408		$	15,327
Noncash investing activities:
Other liabilities related to acquisitions	$	—		$	—		$	2,084		$	—
Contribution of license agreement to joint venture	$	4,795		$	—		$	4,795		$	—

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME – unaudited

(in thousands)


	Common Units (1)					Accumulated Other Comprehensive Income			Noncontrolling interests of PVR (2)			Total			Comprehensive Income
Balance at December 31, 2010		38,293	$	213,646		$	159		$	220,845		$	434,650
Unit-based compensation		24		6,756									6,756
Costs associated with merger				(11,240	)								(11,240	)
Units issued to acquire non-controlling interests		32,665		204,537			250			(204,787	)		—
Distributions paid				(84,302	)					(15,394	)		(99,696	)
Net income (loss)				79,690						(664	)		79,026		$	79,026
Other comprehensive income							366						366			366

Balance at September 30, 2011		70,982	$	409,087		$	775		$	—		$	409,862		$	79,392


	Common Units (1)					Accumulated Other Comprehensive Income (Loss)			Noncontrolling interests of PVR			Total			Comprehensive Income
Balance at December 31, 2009		38,293	$	250,240		$	(544	)	$	235,907		$	485,603
Unit-based compensation				—						6,024			6,024
Loss on issuance of subsidiary units				(1,508	)					1,508			—
Purchase of subsidiary units				(11,665	)					10,573			(1,092	)
Distributions paid				(45,326	)					(46,077	)		(91,403	)
Net income				27,262						18,671			45,933		$	45,933
Other comprehensive income							585			919			1,504			1,504

Balance at September 30, 2010		38,293	$	219,003		$	41		$	227,525		$	446,569		$	47,437

(1)	The outstanding common units have been adjusted to reflect the effect of the Merger; see Note 1, Organization, and Note 2, Basis of Presentation. PVG unitholders received consideration of 0.98 of a PVR common unit for each PVG common unit.

(2)	Effective with the Merger, see Note 1, Organization, and Note 2, Basis of Presentation, noncontrolling interests no longer exist and have become part of common units.

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, 2011

1.	Organization

Penn Virginia Resource Partners, L.P. is a publicly traded Delaware master limited partnership, the limited partner units representing limited partner interests which are listed on the New York Stock Exchange (“NYSE”) under ticker symbol “PVR.” As used in these Notes to Consolidated Financial Statements, the “Partnership,” “PVR,” “we,” “us” or “our” mean Penn Virginia Resource Partners, L.P. and, where the context requires, includes our subsidiaries.

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. 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 located in Illinois, Indiana, Kentucky, New Mexico, Tennessee, Virginia and West Virginia. 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 are a partner in several joint ventures that gather and transport natural gas and water. 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.

On September 21, 2010, we entered into an Agreement and Plan of Merger (the “Merger Agreement”) by and among PVR, 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 PVR. The Merger Agreement received final approval by PVR unitholders on February 16, 2011 and PVG unitholders on March 9, 2011. Pursuant to the Merger Agreement, PVG and PVG GP were merged into Merger Sub, with Merger Sub as the surviving entity (the “Merger”). Merger Sub was subsequently merged into PVR GP, with PVR GP being the surviving entity as a subsidiary of PVR. In the transaction, PVG unitholders received consideration of 0.98 PVR common units for each PVG common unit, representing aggregate consideration of approximately 38.3 million PVR common units. Pursuant to the Merger Agreement and the Fourth Amended and Restated Agreement of Limited Partnership of PVR, the incentive distribution rights held by PVR’s general partner were extinguished, the 2.0% general partner interest in PVR held by PVR’s general partner was converted into a noneconomic management interest and approximately 19.6 million PVR common units owned by PVG were cancelled. The Merger closed on March 10, 2011. After the effective date of the Merger and related transactions, the separate existence of each of PVG, PVG GP and Merger Sub ceased, and PVR GP survives as a wholly-owned subsidiary of PVR.

Historically, PVG’s ownership of PVR’s general partner gave it control of PVR. During the periods that PVG controlled PVR (prior to March 10, 2011), PVG had no substantial assets or liabilities other than those of PVR. PVG’s consolidated financial statements included noncontrolling owners’ interest of consolidated subsidiaries, which reflected the proportion of PVR common units owned by PVR’s unitholders other than PVG. These amounts are reflected in the historical financial balances presented up to consummation of the Merger.

PVG is considered the surviving consolidated entity for accounting purposes, while PVR is the surviving consolidated entity for legal and reporting purposes. The Merger was accounted for as an equity transaction. Therefore, the changes in ownership interests as a result of the Merger did not result in gain or loss recognition.

After the Merger, the board of directors of PVR’s general partner, PVR GP, consisted of nine members, six of whom were existing members of the PVR GP board of directors before the Merger and three of whom were the three existing members of the conflicts committee of the board of directors of PVG GP prior to the Merger. On June 22, 2011, PVR held its annual unitholder meeting and all nine directors were re-elected to serve on the PVR GP board until PVR’s 2012 annual unit holder meeting.

During the nine months ended September 30, 2011 and for the year ended December 31, 2010, we incurred $6.6 million and $4.6 million of direct costs associated with the Merger. The aggregate costs of $11.2 million were charged to partners’ capital upon the effective date of the Merger in 2011. At December 31, 2010, the $4.6 million of costs incurred at that time were included in other long-term assets on the consolidated balance sheet, and were transferred to partners’ capital upon the effective date of the merger. Cumulative costs incurred and paid during the three and nine months ended September 30, 2011 are reported under the caption “Cash paid for merger” in the financing activities section of the consolidated statement of cash flows.

The following diagrams depict the ownership structure of PVR and PVG before and immediately following the Merger:

LOGO

2.	Basis of Presentation

These financial statements were originally the financial statements of PVG prior to the effective date of the Merger. The Merger was accounted for in accordance with consolidation accounting standards for changes in a parent’s ownership interest in a subsidiary. Under these accounting standards, the exchange of PVG common units for PVR common units was accounted for as a PVG equity issuance and PVG was the surviving entity for accounting purposes. Although PVG was the surviving entity for accounting purposes, PVR is the surviving entity for legal and reporting purposes; consequently, the name on these financial statements was changed from “Penn Virginia GP Holdings, L.P.” to “Penn Virginia Resource Partners, L.P.”

The reconciliation of PVR’s net income, as historically reported, to the net income reported in these financial statements is as follows (in thousands):


	Three Months Ended September 30,			Nine Months Ended September 30,
	2010			2010
Net income, as previously reported	$	10,774		$	48,685
Adjustments:
General and administrative expense (a)		(637	)		(2,791	)
Interest income		8			39

Net income	$	10,145		$	45,933

(a)	PVG incurred general and administrative expenses primarily related to audit fees, board of director fees, insurance and SEC filing expenses.

Pursuant to the Merger, PVG’s unitholders received 0.98 of a PVR common unit for each PVG common unit they owned, or approximately 38.3 million of PVR common units in the aggregate, in exchange for all outstanding PVG common units. Also pursuant to the Merger, approximately 19.6 million PVR common units that were held by PVG were cancelled. As a result, PVR’s common units outstanding increased from 52.3 million to 71.0 million. However, for historical reporting purposes, the impact of this change was accounted for as a reverse unit split of 0.98 to 1.0. Therefore, since PVG was the surviving entity for accounting purposes, the weighted average common units outstanding used for basic and diluted earnings per unit calculations are PVG’s historical weighted average common units outstanding adjusted for the retrospective application of the reverse unit split. Amounts reflecting historical PVG common unit and per common unit amounts included in this report have been restated for the reverse unit split.

Our Consolidated Financial Statements include the accounts of PVR 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 PVR’s and PVG’s Annual Reports on Form 10-K for the year ended December 31, 2010. Operating results for the three and nine months ended September 30, 2011 are not necessarily indicative of the results that may be expected for the year ending December 31, 2011.

Management has evaluated all activities of PVR 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, but disclosure is required in the Notes to Consolidated Financial Statements. See Note 13 to the Consolidated Financial Statements.

In June 2011, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) aimed at increasing the prominence of other comprehensive income in the financial statements by requiring comprehensive income to be reported in either a single statement or in two consecutive statements reporting net income and other comprehensive income. This amendment does not change items that are reported in other comprehensive income or requirements to report reclassification of items from other comprehensive income to net income. This ASU eliminates the option to report other comprehensive income and its components in the statement of changes in partners’ capital. We will be required to adopt the guidance for fiscal years, and interim periods within those years, beginning after December 15, 2011. Management is considering which presentation would be more beneficial to the readers of our financials and will adopt this ASU for interim periods beginning in 2012.

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

3.	Acquisitions

In the following paragraphs, all references to coal, oil and gas interests acquired are unaudited. The factors we used to determine the fair market value of the acquisition include, but are not limited to, discounted future net cash flows on a risk-adjusted basis, geographic location, quality of resources, potential marketability and financial condition of lessees.

Business Combination

Middle Fork

On January 25, 2011, we completed an acquisition to acquire certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $95.7 million. The results of Middle Fork operations have been included in the consolidated financial statements since that date. The mineral rights include approximately 102 million tons of coal reserves and resources. The coal is primarily steam coal and expands our geographic scope in the Central Appalachia coal region.

We acquired assets of $97.8 million and liabilities of $2.1 million, which primarily represent deferred income. Deferred income represents minimum royalty payments paid by operators of the properties that may be recouped through future production. Funding for the acquisition was provided by borrowings under our revolving credit facility (the “Revolver”).

The Middle Fork acquisition has been accounted for using the purchase method of accounting. Under the purchase method of accounting, the total purchase price has been allocated to the tangible assets acquired and liabilities assumed. Below is the detailed allocation based upon acquisition date fair values:


Fair value of assets acquired and liabilities assumed:
Coal mineral interests	$	94,410
Oil and gas interests		2,857
Land		449
Support equipment		60
Deferred income		(2,018	)
Other liabilities		(42	)

Fair value of assets acquired and liabilities assumed	$	95,716

The following pro forma financial information reflects the consolidated results of our operations as if the Middle Fork acquisition had occurred on January 1, 2010. The pro forma information includes adjustments for royalty revenues, operating expenses, general and administrative expenses, depreciation and depletion of the acquired property and equipment, interest

expense for acquisition debt and the change in weighted average common units resulting from the Merger. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date (in thousands, except per unit data):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Revenues	$	308,352	$	226,046	$	873,054	$	627,054
Net income attributable to PVR	$	35,857	$	7,937	$	79,853	$	28,890
Net income per limited partner unit, basic and diluted	$	0.50	$	0.21	$	1.26	$	0.75

During the year, we have made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions was a net $26.9 million.

4.	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, 2010.

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, 2011, 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 (a Level 1 category fair value measurement). As of September 30, 2011, the fair value of our fixed-rate debt was $285.0 million.

Nonrecurring Fair Value Measurements

We completed the Middle Fork acquisition on January 25, 2011. See Note 3, “Acquisitions,” for a description of this acquisition. In connection with our accounting for this acquisition, 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, involved the estimated fair values of coal minerals and oil and gas royalties along with the related pricing and production activities. The coal minerals acquisition included nonfinancial assets and liabilities that were measured at fair value as of the acquisition date. The total purchase price allocation was $95.7 million.

During the year, we have made other acquisitions that individually and in the aggregate are not material for disclosure purposes. The aggregate cost of all other acquisitions was a net $26.9 million.

The following table summarizes the fair value estimates for nonfinancial assets and liabilities measured at fair value on a nonrecurring basis by category as of the acquisition date:


				Fair Value Measurements, Using
Description	Fair Value Measurements at Acquisition Date			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Middle Fork assets (1)	$	97,776		$	—	$	—	$	97,776
Middle Fork liabilities (1)		(2,060	)		—		—		(2,060	)
Other acquisitions, net (2)		26,919			—		—		26,919

Total	$	122,635		$	—	$	—	$	122,635

(1)	The Middle Fork assets and liabilities were acquired on January 25, 2011.

(2)	Other acquisitions were completed in the second and third quarters of 2011.

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 these assets and liabilities for the periods presented:


				Fair Value Measurements at September 30, 2011, Using
Description	Fair Value Measurements at September 30, 2011			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	$	(3,048	)	$	—	$	(3,048	)	$	—
Interest rate swap liabilities – noncurrent		(376	)		—		(376	)		—
Commodity derivative assets – current		1,381			—		1,381			—
Commodity derivative assets – noncurrent		332			—		332			—
Commodity derivative liabilities – current		(8,479	)		—		(8,479	)		—
Commodity derivative liabilities – noncurrent		(879	)		—		(879	)		—

Total	$	(11,069	)	$	—	$	(11,069	)	$	—


				Fair Value Measurements at December 31, 2010, Using
Description	Fair Value Measurements at December 31, 2010			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap liabilities – current	$	(7,647	)	$	—	$	(7,647	)	$	—
Interest rate swap liabilities – noncurrent		(1,037	)		—		(1,037	)		—
Commodity derivative liabilities – current		(11,869	)		—		(11,869	)		—
Commodity derivative liabilities – noncurrent		(4,070	)		—		(4,070	)		—

Total	$	(24,623	)	$	—	$	(24,623	)	$	—

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.

•

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 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.

5.	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, 2011:


	Average Volume Per Day			Swap Price			Weighted Average Price				Fair Value at September 30, 2011
	Average Volume Per Day			Swap Price			Put		Call		Fair Value at September 30, 2011
NGL – natural gasoline collar		(gallons	)					(per gallon)
Fourth quarter 2011		95,000					$	1.57	$	1.94	$	(2,492	)
NGL – natural gasoline collar		(gallons	)					(per gallon)
First quarter 2012 through fourth quarter 2012		54,000					$	1.75	$	2.02		(3,138	)
Crude oil collar		(barrels	)					(per barrel)
Fourth quarter 2011		400					$	75.00	$	98.50		109
Crude oil swap		(barrels	)		(per barrel	)
First quarter 2012 through fourth quarter 2012		600		$	88.62							1,604
Natural gas purchase swap		(MMBtu	)		(MMBtu	)
Fourth quarter 2011		6,500		$	5.80							(1,193	)
Natural gas purchase swap		(MMBtu	)		(MMBtu	)
First quarter 2012 through fourth quarter 2012		4,000		$	5.195							(1,370	)
Settlements to be paid in subsequent period												(1,165	)

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 as of September 30, 2011:


	Notional Amounts (in millions)		Swap Interest Rates (1)					Fair Value at September 30, 2011
Term	Notional Amounts (in millions)		Pay			Receive		Fair Value at September 30, 2011
October 2011 – December 2011	$	250.0		3.37	%		LIBOR	$	(1,907	)
January 2011 – December 2012	$	100.0		2.09	%		LIBOR	$	(1,517	)

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

For the Interest Rate Swaps, we reported a (i) net derivative liability of $3.4 million at September 30, 2011 and (ii) gain in accumulated other comprehensive income (“AOCI”) of $0.8 million as of September 30, 2011. In connection with periodic settlements, we reclassified a total of $0.4 million of net hedging losses on the Interest Rate Swaps from AOCI to the derivatives line on the Consolidated Statements of Income during the nine months ended September 30, 2011. 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 gains (losses) on our Consolidated Statements of Income for the periods presented:


	Location of derivatives recognized in income statement	Three Months Ended September 30,						Nine Months Ended September 30,
	Location of derivatives recognized in income statement	2011			2010			2011			2010
Derivatives not designated as hedging instruments:
Interest rate contracts (1)	Interest expense	$	—		$	—		$	—		$	(1,090	)
Interest rate contracts	Derivatives		(58	)		(2,568	)		(956	)		(7,739	)
Commodity contracts	Derivatives		8,748			(8,452	)		(5,333	)		(3,775	)

Total increase (decrease) in net income resulting from derivatives		$	8,690		$	(11,020	)	$	(6,289	)	$	(12,604	)

Realized and unrealized derivative impact:
Cash paid for commodity and interest rate contract settlements	Derivatives	$	(6,699	)	$	(2,435	)	$	(19,477	)	$	(6,493	)
Unrealized derivative gains (losses) (2)			15,389			(8,585	)		13,188			(6,111	)

Total increase (decrease) in net income resulting from derivatives		$	8,690		$	(11,020	)	$	(6,289	)	$	(12,604	)

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

(2)	This activity represents unrealized gains (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:


	Balance Sheet Location	Fair Values as of September 30, 2011				Fair Values as of December 31, 2010
	Balance Sheet Location	Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative assets/liabilities – current	$	—	$	3,048	$	—	$	7,647
Interest rate contracts	Derivative assets/liabilities – noncurrent		—		376		—		1,037
Commodity contracts	Derivative assets/liabilities – current		1,381		8,479		—		11,869
Commodity contracts	Derivative assets/liabilities – noncurrent		332		879		—		4,070

Total derivatives not designated as hedging instruments		$	1,713	$	12,782	$	—	$	24,623

Total fair value of derivative instruments		$	1,713	$	12,782	$	—	$	24,623

As of September 30, 2011, we were not party to derivative instruments that were classified as fair value hedges or trading securities. In addition, as of September 30, 2011, we were not party to derivative instruments containing credit risk contingencies.

6.	Equity Investments

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch diameter steel pipeline will largely parallel the trunk line of our existing gathering system in Lycoming County. As of September 30, 2011 our non-cash contribution to the joint venture was $4.8 million.

In accordance with the equity method of accounting, we recognized earnings from all equity investments in the aggregate of $4.3 million and $6.5 million for the nine months ended September 30, 2011 and 2010, with a corresponding increase in the investment. The equity investments generally pay quarterly distributions on their cash flow. We received distributions of $8.9 million and $9.0 million for the nine months ended September 30, 2011 and 2010. Equity earnings related to equity investments 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, 2011		December 31, 2010
Current assets	$	33,618	$	43,367
Noncurrent assets	$	213,591	$	203,595
Current liabilities	$	13,515	$	6,890
Noncurrent liabilities	$	2,520	$	5,147

	Nine Months Ended September 30,
	2011		2010
Revenues	$	43,074	$	52,722
Expenses	$	26,091	$	25,438
Net income	$	16,983	$	27,284

7.	Long-term Debt

Revolver

On April 19, 2011, our wholly-owned subsidiary, PVR Finco LLC, entered into the first amendment to the amended and restated secured credit agreement increasing our borrowing capacity under the Revolver from $850.0 million to $1.0 billion and extending the maturity date to April 19, 2016. PVR Finco LLC has an option to increase the commitments under the Revolver by up to an additional $200.0 million, to a total of $1.2 billion, upon receipt of commitments from one or more lenders. The amendment did not change the collateral provisions of the Revolver which is secured by substantially all of our assets, including recent acquisitions. 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 0.75% to 1.75% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based indebtedness option. As of September 30, 2011, net of outstanding indebtedness of $635.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $363.4 million on the Revolver. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2011 was approximately 2.7%. We do not have a public rating for the Revolver. As of September 30, 2011, we were in compliance with all covenants under the Revolver.

8.	Partners’ Capital and Distributions

As of September 30, 2011, partners’ capital consisted of approximately 71.0 million common units. As noted in the Consolidated Statement of Partners’ Capital and Comprehensive Income and described in Note 1, Organization, and Note 2, Basis of Presentation, our outstanding number of units has changed significantly in connection with the Merger.

Net Income per Limited Partner Unit

Basic net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partner and vested deferred common 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 and vested deferred common units outstanding during the period and, when dilutive, phantom units. For the three and nine months ended September 30, 2011, weighted average awards of 39 thousand and 24 thousand phantom units were excluded from the diluted net income per limited partner unit calculation because the inclusion of these phantom units would have had an antidilutive effect. The three and nine months ended September 30, 2010 computation of net income per limited partner unit relates to the financial statements of PVG prior to the effective date of the Merger. For the three and nine months ended September 30, 2010, PVG did not have any phantom units or other participating securities outstanding, which would affect the computation of net income per limited partner unit.

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,
	2011			2010			2011			2010
Net income	$	35,857		$	10,145		$	79,026		$	45,933
Net loss (income) attributable to noncontrolling interests, pre-merger (Note 1)		—			(2,864	)		664			(18,671	)

Net income attributable to Penn Virginia Resource Partners, L.P.	$	35,857		$	7,281		$	79,690		$	27,262
Adjustments:
Distributions to participating securities		(111	)		—			(300	)		—
Participating securities’ allocable share of net income		(111	)		—			(256	)		—

Net income allocable to limited partners, basic	$	35,635		$	7,281		$	79,134		$	27,262
Participating securities’ allocable share of net income		111			—			256			—
Participating securities’ earnings reallocated to unvested securities		(111	)		—			(256	)		—

Net income allocable to limited partners, diluted	$	35,635		$	7,281		$	79,134		$	27,262

Net income per limited partner unit, basic	$	0.50		$	0.19		$	1.26		$	0.71
Net income per limited partner unit, basic and diluted	$	0.50		$	0.19		$	1.26		$	0.71
Weighted average limited partner units, basic and diluted		71,197			38,293			63,019			38,293

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, prior to the Merger, 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,
	2011		2010		2011		2010
PVG limited partners	$	—	$	15,239	$	15,239	$	45,326
PVR limited partners (1)		34,777		15,347		84,188		45,671
PVR phantom units		110		33		269		406

Total cash distribution paid during period	$	34,887	$	30,619	$	99,696	$	91,403

(1)	PVR limited partner unit distributions represent distributions paid to public unitholders and not to units owned by PVG prior to the Merger.

9.	Related-Party Transactions

In June 2010, Penn Virginia Corporation (“PVA”) sold its remaining interest in PVG and as a result, PVA no longer owned 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. Related party transactions included charges from PVA for certain corporate administrative expenses which were 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 amounts noted below represent related party transactions prior to June 7, 2010 (date of divestiture).


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Consolidated Statements of Income:
Natural gas midstream revenues	$	—	$	—	$	—	$	29,002
Other income	$	—	$	—	$	—	$	787
Cost of gas purchased	$	—	$	—	$	—	$	27,780
General and administrative	$	—	$	—	$	—	$	1,906

10.

Unit-Based Compensation

The Penn Virginia Resource GP, LLC Sixth Amended and Restated Long-Term Incentive Plan (the “LTIP”) permits the grant of common units, deferred common units, unit options, 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, and we recognize compensation expense related to those grants on a straight-line basis over the vesting period. Compensation expense related to these grants is recorded in the general and administrative expenses caption on our Consolidated Statements of Income. During the nine months ended September 30, 2011, we granted 264 thousand phantom units at a weighted average grant-date fair value of $29.16, including 155 thousand time-based phantom units and 109 thousand performance-based phantom units.

Time-based phantom units vest over a three-year period, with one-third vesting in each year. Some of the phantom units vested during the third quarter. A portion of the vested units were withheld for payroll taxes with the recipient receiving the net vested units.

Performance-based phantom units cliff-vest at the end of a three year period. The number of units that vest could range from 0% to 200% and depends on the outcome of unit market performance compared to peers and key results of operations metrics. Performance-based phantom units are entitled to forfeitable distribution equivalent rights which accumulate over the term of the units and will be paid in cash to the grantees at the date of vesting. The fair value of each performance-based phantom unit was estimated on the date of grant as $30.92 using a Monte Carlo simulation approach that uses the assumptions noted in the following table. Expected volatilities are based on historical changes in the market value of our common units. We base the risk-free interest rate on the U.S. Treasury rate for the week of the grant having a term equal to the expected life of the phantom units, continuously compounded.


	2011
Expected volatility		54.53	%
Expected life		2.6 years
Risk-free interest rate		0.83	%

Prior to the Merger, the PVG GP, LLC Amended and Restated Long-Term Incentive Plan (“the PVG LTIP”) likewise permitted the granting of PVG common units, deferred common units, unit options, restricted units and phantom units to employees and directors of the general partner and its affiliates. At the time of the Merger, deferred PVG common units held on account of PVG’s directors were automatically converted to deferred PVR common units at the rate of 0.98 deferred PVR common units for each deferred PVG common unit.

In connection with the normal three-year vesting of phantom and restricted units, as well as common unit and deferred common unit awards, we recognized the following expense during the periods presented: .


	Three Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011		2010
Restricted units	$	—	$	—	$	—	$	1,172
Phantom units		826		130		2,186		6,017
Director deferred and common units		140		285		619		862

	$	966	$	415	$	2,805	$	8,051

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 adverse effect on our financial position, results of operations or cash flows.

Environmental Compliance

As of September 30, 2011 and December 31, 2010, our environmental liabilities were $0.8 million and $0.9 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, 2011, revenues of each of our four largest natural gas midstream segment customers were $124.4 million, $76.5 million, $75.3 million and $72.7 million, for an aggregate of 40% of our total consolidated revenues. At September 30, 2011, 35% 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 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 and water.

•

The corporate and other caption primarily represents corporate functions.

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,
	2011		2010		2011			2010
Coal and natural resource management	$	47,456	$	40,408	$	29,831		$	26,374
Natural gas midstream		260,896		182,421		7,744			5,956
Corporate and other		—		—		—			(637	)

Totals	$	308,352	$	222,829	$	37,575		$	31,693

Interest expense						(10,528	)		(10,639	)
Derivatives						8,690			(11,020	)
Other						120			111

Net income					$	35,857		$	10,145


	Additions to property and equipment				Depreciation, depletion & amortization
	Three Months Ended September 30,				Three Months Ended September 30,
	2011		2010		2011			2010
Coal and natural resource management	$	190	$	169	$	9,572		$	7,440
Natural gas midstream		66,905		33,077		12,891			11,262

Totals	$	67,095	$	33,246	$	22,463		$	18,702


	Revenues				Operating income
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
Coal and natural resource management	$	144,429	$	114,550	$	90,485		$	71,516
Natural gas midstream		727,772		504,189		28,252			13,436
Corporate and other		—		—		—			(2,791	)

Totals	$	872,201	$	618,739	$	118,737		$	82,161

Interest expense						(33,806	)		(25,368	)
Derivatives						(6,289	)		(11,514	)
Other						384			654

Net income					$	79,026		$	45,933


	Additions to property and equipment				Depreciation, depletion & amortization
	Nine Months Ended September 30,				Nine Months Ended September 30,
	2011		2010		2011			2010
Coal and natural resource management	$	110,898	$	18,283	$	27,978		$	22,145
Natural gas midstream		153,033		57,560		37,379			32,638

Totals	$	263,931	$	75,843	$	65,357		$	54,783


	Total assets at
	September 30,		December 31,
	2011		2010
Coal and natural resource management	$	682,307	$	585,559
Natural gas midstream		828,353		711,942
Corporate and other		—		6,704

Totals	$	1,510,660	$	1,304,205

13.

Subsequent Event

In October 2011, the Coal and Natural Resources segment acquired properties which include coal, timber and oil and gas assets for approximately $21.6 million in West Virginia. We used borrowings under our Revolver to finance this acquisition.

Forward-Looking Statements

Certain statements contained herein include “forward-looking statements.” All statements that express beliefs, expectations, estimates or intentions, as well as those that are not statements of historical fact, are forward-looking statements. Words such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements. 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 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, or at all;

•

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, 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, 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,” “PVR,” “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 principally engaged in the management of coal and natural resource properties and the gathering and processing of natural gas in the United States.

After the Merger, the board of directors of PVR’s general partner, PVR GP, consisted of nine members, six of whom were existing members of the PVR GP board of directors before the Merger and three of whom were the three existing members of the conflicts committee of the board of directors of PVG GP prior to the Merger. On June 22, 2011, PVR held its annual meeting and all nine directors were re-elected to serve on the PVR GP board until PVR’s 2012 annual unitholder meeting.

The following diagrams depict the ownership structure of PVR and PVG before and immediately following the Merger:

LOGO

Key Developments

For the nine months ended September 30, 2011, the following general business developments and corporate actions had an impact, or will have an impact, on our results of operations. A discussion of these key developments follows:

Coal and Natural Resource Management Segment

Middle Fork Acquisition

On January 25, 2011, we completed an acquisition to acquire certain mineral rights and associated oil and gas royalty interests in Kentucky and Tennessee for approximately $95.7 million. The mineral rights include approximately 102 million tons of coal reserves and resources. The coal is primarily steam coal and expands our geographic scope in the Central Appalachia coal region.

Oatsville Reserves

In June 2011, we acquired 26.8 million tons of additional coal reserves in the Illinois Basin for $13.5 million. The Oatsville Reserve properties are deep minable Springfield V seam coal located on approximately 5,875 acres in Gibson and Pike counties in Indiana.

Natural Gas Midstream Segment

Aqua Joint Venture

In September 2011, we entered into a joint venture to construct and operate a pipeline system to supply fresh water to natural gas producers drilling in the Marcellus Shale in Pennsylvania. The 12-inch diameter steel pipeline will largely parallel the trunk line of our existing gathering system in Lycoming County. As of September 30, 2011 our contribution to the joint venture was $4.8 million.

Marcellus Shale Construction

During 2010, we began construction of gathering systems in Wyoming and Lycoming Counties in Pennsylvania. We have completed initial construction of 12-inch gas gathering pipelines in Wyoming County and began gathering natural gas on the system in June 2010. In February 2011, we commenced operations on the first phase of the Lycoming County system. In April 2011, we also began construction on the second phase of the Lycoming County system, which is expected to be operational in the first quarter of 2012. Construction and development to provide gathering, compression and related services in Lycoming and Wyoming Counties is ongoing. These Wyoming and Lycoming Counties gathering and transportation infrastructures are expected to capture anticipated volumes in the Marcellus Shale area, where we have been spending, and expect to continue to spend, a significant portion of our growth capital over the next year, and for the foreseeable future.

Panhandle

Due to the increased well development activities in the Panhandle region of the Midstream operations, our system volumes have increased significantly over past years’ volumes. The increase in the volumes we have under contract in the Granite Wash has outpaced the capacity of our processing plants in the Panhandle. Further, third-party processing plants in the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during the third quarter. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue through the fourth quarter and the beginning of the first quarter 2012. We have taken affirmative steps to alleviate this processing capacity constraint, including the acquisition of the Antelope Hills processing facility in June 2011, the previously announced Phase One expansion of the Antelope Hills facility from 20 mmcf/day to 80 mmcf/day, and the most recently announced Phase Two expansion of that facility to bring the processing capacity to 140 mmcf/day. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational in the third quarter of 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. We are also improving the connectivity between our Antelope Hills, Beaver and Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

2011 Commodity Prices

Coal royalties, which accounted for 86% of the coal and natural resource management segment revenues for the nine months ended September 30, 2011 and 2010, were higher as compared to 2010. The increase was attributed to increased production and higher realized coal royalty per ton primarily in the Central Appalachian and San Juan regions. Average coal

prices received by lessees have increased in 2011 compared to the same period of 2010 due to strong market pricing for thermal and metallurgical coal.

The average commodity prices for crude oil and natural gas liquids, or NGLs, for 2011 increased from levels experienced in 2010, while natural gas prices decreased for the comparable periods.

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 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 105% and 62% of our commodity-sensitive volumes in 2011 and 2012. The coverage amounts are high due to the processing capacity constraints in the Panhandle region. These constraints have caused PVR to bypass more of its owned natural gas without processing; lowering the net NGL recoveries specific to PVR. Historically, we have targeted hedging 50% to 60% of our commodity sensitive volumes.

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 debt and equity offerings. As discussed in more detail in “– Sources of Liquidity” below, as of September 30, 2011, we had availability of $363.4 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), debt service 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, most of which are beyond our control.

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


	Nine Months Ended September 30,
	2011			2010
Cash flows from operating activities:
Net income	$	79,026		$	45,933
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		63,435			72,939
Net changes in operating assets and liabilities		(153	)		21,959

Net cash provided by operating activities		142,308			140,831
Net cash used in investing activities (summarized)		(261,373	)		(74,858	)
Net cash provided by (used in) financing activities (summarized)		117,009			(66,772	)

Net decrease in cash and cash equivalents	$	(2,056	)	$	(799	)

Cash Flows From Operating Activities

The overall increase in net cash provided by operating activities in the nine months ended September 30, 2011 as compared to the same period in 2010 was driven by an increase in coal royalties and an increase in the natural gas midstream segment’s gross margin. These increases were partially offset by net change in operating assets and liabilities, increased operating expenses, interest expense and derivative settlements paid.

Cash Flows From Investing Activities

Net cash used in investing activities was primarily for capital expenditures. The following table sets forth our capital expenditures program, adjusted for accruals and noncash items, for the periods presented:


	Nine Months Ended September 30,
	2011		2010
Coal and natural resource management
Acquisitions	$	111,976	$	17,870
Maintenance		687		484

Total		112,663		18,354

Natural gas midstream
Acquisitions		12,243		—
Internal growth		127,498		53,011
Maintenance		7,845		9,873

Total		147,586		62,884

Total capital expenditures	$	260,249	$	81,238

In January 2011, we completed the acquisition of the Middle Fork properties, which added significant coal reserves to our coal and natural resource segment in the Central Appalachia region. In June 2011, we completed two additional acquisitions. The Oatsville acquisition was in the Illinois Basin and we acquired 26.8 million tons of additional coal reserves. The Antelope Hills plant acquisition added capacity to our Panhandle system in our Natural Gas Midstream segment. Our natural gas midstream internal growth capital expenditures for the nine months ended September 30, 2011 and 2010 were expended primarily to expand our operational footprint in our Marcellus Shale and Panhandle systems.

Cash Flows From Financing Activities

During the nine months ended September 30, 2011, we incurred net borrowings of $227.0 million to fund our coal and natural resources and natural gas midstream acquisitions and to finance the natural gas midstream capital expenditures. During the nine months ended September 30, 2010, we issued $300.0 million in senior notes and used the proceeds, net of expenses, to pay down the Revolver. We also paid $6.6 million of direct costs incurred related to the Merger in 2011, and $3.7 million and $19.2 million of debt issuance costs for the nine months ended September 30, 2011 and 2010. During the nine months ended September 30, 2011 and 2010 we paid cash distributions to our unitholders of $99.7 million and $91.4 million.

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.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CERTAIN NON-GAAP FINANCIAL MEASURES – unaudited

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2011			2010			2011			2010
Reconciliation of GAAP “Operating Income” to Non-GAAP “EBITDA”
Operating income	$	37,575		$	31,693		$	118,737		$	82,161
Depreciation, depletion and amortization		22,463			18,702			65,357			54,783

EBITDA (a)	$	60,038		$	50,395		$	184,094		$	136,944


Reconciliation of GAAP “Net income” to Non-GAAP “Distributable cash flow”
Net income	$	35,857		$	10,145		$	79,026		$	45,933
Depreciation, depletion and amortization		22,463			18,702			65,357			54,783
Commodity derivative contracts:
Derivative losses (gains) included in net income		(8,690	)		11,020			6,289			12,604
Cash payments to settle derivatives for the period		(6,699	)		(2,435	)		(19,477	)		(6,493	)
Equity earnings from joint ventures, net of distributions		2,818			110			4,635			2,500
Maintenance capital expenditures		(2,884	)		(4,246	)		(8,532	)		(10,357	)
Replacement capital expenditures		(6,725	)		—			(20,175	)		—

Distributable cash flow (b)	$	36,140		$	33,296		$	107,123		$	98,970


Distribution to Partners:
PVG limited partners	$	—		$	15,239		$	15,239		$	45,326
PVR limited partners (c)		34,777			15,347			84,188			45,671
PVR phantom units (d)		110			33			269			406

Total cash distribution paid during period	$	34,887		$	30,619		$	99,696		$	91,403


Reconciliation of GAAP “Net income” to Non-GAAP “Net income as adjusted”
Net income	$	35,857		$	10,145		$	79,026		$	45,933
Adjustments for derivatives:
Derivative losses (gains) included in net income		(8,690	)		11,020			6,289			12,604
Cash payments to settle derivatives for the period		(6,699	)		(2,435	)		(19,477	)		(6,493	)

Net income, as adjusted (e)	$	20,468		$	18,730		$	65,838		$	52,044

(a)

EBITDA, or earnings before interest, tax and depreciation, depletion and amortization (“DD&A”), represents operating income plus DD&A, plus impairments. 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 coal and natural gas midstream industries. We use this information for comparative purposes within the industry. EBITDA 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.

(b)

Distributable cash flow represents net income plus DD&A expenses, plus impairments, plus (minus) derivative losses (gains) included in net income, plus (minus) cash received (paid) to settle derivatives, minus equity earnings in joint ventures, plus cash distributions from joint ventures, minus maintenance capital expenditures, minus replacement 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 the 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.

(c)	PVR limited partner unit distributions represent distributions paid to public unitholders and not units owned by PVG prior to the Merger.

(d)	Phantom unit grants were made under our long-term incentive plan. Service based phantom units receive nonforfeitable distribution rights; thus, we have presented distributions paid to phantom unit holders in our total distributions paid to Partners.

(e)

Net income, as adjusted, represents net income adjusted to exclude the effects of non-cash changes in the fair value of derivatives and impairments. 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.

Sources of Liquidity

Long-Term Debt

Revolver. On April 19, 2011, we entered into an amended and restated secured credit agreement increasing our borrowing capacity under the Revolver from $850 million to $1.0 billion and extending the maturity date until April 19, 2016. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. As of April 19, 2011, interest is payable at the base rate plus an applicable margin ranging from 0.75% to 1.75% if we select the base rate indebtedness option under the Revolver or at a rate derived from LIBOR plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based indebtedness option. As of September 30, 2011, net of outstanding indebtedness of $635.0 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $363.4 million on the $1.0 billion Revolver. The Revolver is available to provide funds for general partnership purposes, including working capital, capital expenditures, acquisitions and quarterly distributions. The weighted average interest rate on borrowings outstanding under the Revolver during the nine months ended September 30, 2011 was approximately 2.7%. We do not have a public rating for the Revolver. As of September 30, 2011, we were in compliance with all of our covenants under the Revolver.

Interest Rate Swaps. We 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, 2011:


	Notional Amounts (in millions)		Swap Interest Rates (1)
Term	Notional Amounts (in millions)		Pay			Receive
October 2011 – 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 2.25% in effect as of September 30, 2011, the total interest rate on the $250.0 million portion of the Revolver borrowings covered by the Interest Rate Swaps was 5.62% as of September 30, 2011.

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 8.25%. The net proceeds from the sale of the Senior Notes of $292.6 million, after deducting fees and expenses of $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.

Future Capital Needs and Commitments

As of September 30, 2011, our remaining borrowing capacity under the $1.0 billion Revolver of $363.4 million is sufficient to meet our anticipated 2011 capital needs and commitments (other than major capital improvements or acquisitions). Our short-term cash requirements for operating expenses and quarterly distributions to our unitholders are expected to be funded through operating cash flows. In 2011, we

expect to invest approximately $180 million to $200 million in internal growth capital, excluding acquisitions. The majority of the 2011 internal growth capital is expected to be incurred in the natural gas midstream segment, primarily in the Marcellus Shale region. Long-term cash requirements for acquisitions and internal growth capital 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,
	2011			2010			2011			2010
Revenues	$	308,352		$	222,829		$	872,201		$	618,739
Expenses		(270,777	)		(191,136	)		(753,464	)		(536,578	)

Operating income		37,575			31,693			118,737			82,161
Other expense		(1,718	)		(21,548	)		(39,711	)		(36,228	)

Net income		35,857			10,145			79,026			45,933
Net loss (income) attributable to noncontrolling interests, pre-merger (Note 1)		—			(2,864	)		664			(18,671	)

Net income attributable to Penn Virginia Resource Partners, L.P.	$	35,857		$	7,281		$	79,690		$	27,262

Coal and Natural Resource Management Segment

Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010

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 Favorable (Unfavorable)
	2011		2010		Favorable (Unfavorable)			% Change Favorable (Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	40,977	$	34,983	$	5,994			17	%
Coal services		2,151		1,975		176			9	%
Timber		1,457		1,437		20			1	%
Oil and gas royalty		1,234		631		603			96	%
Other		1,637		1,382		255			18	%

Total revenues		47,456		40,408		7,048			17	%

Expenses
Operating		4,282		2,908		(1,374	)		(47	%)
General and administrative		3,771		3,686		(85	)		(2	%)
Depreciation, depletion and amortization		9,572		7,440		(2,132	)		(29	%)

Total expenses		17,625		14,034		(3,591	)		(26	%)

Operating income	$	29,831	$	26,374	$	3,457			13	%


Other data
Coal royalty tons by region
Central Appalachia		4,753		4,805		(52	)		(1	%)
Northern Appalachia		598		828		(230	)		(28	%)
Illinois Basin		1,191		987		204			21	%
San Juan Basin		2,937		1,910		1,027			54	%

Total tons		9,479		8,530		949			11	%

Coal royalties revenues by region
Central Appalachia	$	29,219	$	25,868	$	3,351			13	%
Northern Appalachia		1,821		2,177		(356	)		(16	%)
Illinois Basin		3,327		2,756		571			21	%
San Juan Basin		6,610		4,182		2,428			58	%

Total royalties	$	40,977	$	34,983	$	5,994			17	%

Coal royalties per ton by region ($/ton)
Central Appalachia	$	6.15	$	5.38	$	0.77			14	%
Northern Appalachia		3.05		2.63		0.42			16	%
Illinois Basin		2.79		2.79		—			0	%
San Juan Basin		2.25		2.19		0.06			3	%

Average royalties per ton	$	4.32	$	4.10	$	0.22			5	%

Revenues

Coal royalties revenues increased due to higher production and realized coal royalties per ton. The Middle Fork acquisition on January 25, 2011 contributed $3.2 million to the Central Appalachia coal royalties and 0.5 million tons of coal production. Offsetting the newly acquired production in the Central Appalachia region was a decrease in production related to the temporary movement of longwall operations off of PVR’s property. Equipment added during 2010 to the mines in the San Juan Basin continues to increase production and related coal royalties compared to the prior year.

Coal royalties per ton increased in all regions, except for the Illinois Basin, which did not change, for the third quarter of 2011 compared to the same quarter of last year. In Central Appalachia, average coal prices received by lessees have increased due to the strong market pricing for thermal and metallurgical coal.

Consistent with the increase in coal production, the coal services revenues have increased in 2011.

Oil and gas royalty income has increased in the third quarter of 2011 over the same period of 2010 due to the 2011 settlement against a producer for deductions made on past royalties, as well as the $0.2 million royalties earned from the Middle Fork acquisition.

Other revenues in the third quarter of 2011 have increased due to minimum royalty forfeitures. Based upon lease contracts, which vary by lessee, lessees paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred after the exhaustion of that time period, the minimum payments are recognized into earnings.

Expenses

Operating expenses have increased primarily due to coal royalty costs and the recent Middle Fork acquisition. Increased mining activity by our lessees from subleased properties in the Central Appalachia region increased coal royalties expense. Mining activity on our subleased property fluctuates between periods due to the proximity of our property boundaries and other mineral owners.

DD&A expenses increased for the comparative periods due to the increase in coal production and related depletion expense.

Nine Months Ended September 30, 2011 Compared with Nine Months Ended September 30, 2010

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 Favorable (Unfavorable)
	2011		2010		Favorable (Unfavorable)			% Change Favorable (Unfavorable)
Financial Highlights
Revenues
Coal royalties	$	124,546	$	98,088	$	26,458			27	%
Coal services		6,739		5,976		763			13	%
Timber		3,834		4,488		(654	)		(15	%)
Oil and gas royalty		3,016		2,000		1,016			51	%
Other		6,294		3,998		2,296			57	%

Total revenues		144,429		114,550		29,879			26	%

Expenses
Operating		11,815		7,670		(4,145	)		(54	%)
General and administrative		14,151		13,219		(932	)		(7	%)
Depreciation, depletion and amortization		27,978		22,145		(5,833	)		(26	%)

Total expenses		53,944		43,034		(10,910	)		(25	%)

Operating income	$	90,485	$	71,516		18,969			27	%


Other data
Coal royalty tons by region
Central Appalachia		15,163		13,746		1,417			10	%
Northern Appalachia		2,840		2,935		(95	)		(3	%)
Illinois Basin		3,580		3,176		404			13	%
San Juan Basin		7,918		5,788		2,130			37	%

Total tons		29,501		25,645		3,856			15	%

Coal royalties revenues by region
Central Appalachia	$	91,069	$	70,592	$	20,477			29	%
Northern Appalachia		6,306		6,137		169			3	%
Illinois Basin		9,302		8,685		617			7	%
San Juan Basin		17,869		12,674		5,195			41	%

Total royalties	$	124,546	$	98,088	$	26,458			27	%

Coal royalties per ton by region ($/ton)
Central Appalachia	$	6.01	$	5.14	$	0.87			17	%
Northern Appalachia		2.22		2.09		0.13			6	%
Illinois Basin		2.60		2.73		(0.13	)		(5	%)
San Juan Basin		2.26		2.19		0.07			3	%

Average royalties per ton	$	4.22	$	3.82	$	0.40			10	%

Revenues

Coal royalties revenues increased due to higher production and realized coal royalties per ton. The Middle Fork acquisition on January 25, 2011 contributed $8.2 million to Central Appalachia coal royalties and 1.3 million tons of coal production. Improved mining conditions, new mines starting up and the metallurgical coal market accounted for the remainder of the tonnage increase in Central Appalachia. Equipment added during 2010 to the mines in the San Juan Basin continues to increase production and related coal royalties compared to the prior year.

Coal royalties per ton increased in all regions in 2011 compared to last year, except for the Illinois Basin. In Central Appalachia, average coal prices received by lessees have increased due to the strong market pricing for thermal and metallurgical coal. The reduced realized royalty rate in the Illinois Basin is due to contractual changes in royalties we receive on some properties in this region.

Consistent with the increase in coal production, the coal services revenues have increased in 2011.

Timber revenues have decreased due to a decrease in timber harvested and average price received per board foot this year. These decreases are associated with the depressed construction and furniture making industries.

Oil and gas royalty income has increased in 2011 due to a settlement against a producer for deductions made on past royalties. The Middle Fork acquisition and the $0.4 million royalties earned from these properties have also contributed to the increase.

Other revenues in 2011 have increased due to minimum royalty forfeitures. Based upon lease contracts, which vary by lessee, lessees paying minimum royalties have an established time to recoup minimum royalties paid. If the stated levels of production have not occurred after the exhaustion of that time period, the minimum payments are recognized into earnings. Additionally, a gain on sale of property to a local oil and gas company related to their exploration activities was recognized in the second quarter of 2011 contributing to the increased other revenues for the year.

Expenses

General and administrative expenses increased as a result of our change in management structure related to the Merger and some shared costs (such as executive and legal costs) with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also contributing to the increase were due diligence costs related to a recent acquisition. Offsetting these increases are lower employee costs related to equity compensation. In the second quarter of last year, there was an acceleration of recognized equity compensation due to Penn Virginia Corporation’s divestiture of its interest in PVG.

DD&A expenses increased for the comparative periods due to the increase in coal production and related depletion expense.

Natural Gas Midstream Segment

Three Months Ended September 30, 2011 Compared with Three Months Ended September 30, 2010

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 Favorable (Unfavorable)
	2011			2010			Favorable (Unfavorable)			% Change Favorable (Unfavorable)
Financial Highlights
Revenues
Residue gas	$	120,240		$	98,534		$	21,706			22	%
Natural gas liquids		121,121			73,500			47,621			65	%
Condensate		8,268			4,814			3,454			72	%
Gathering, processing and transportation fees		10,081			3,359			6,722			200	%

Total natural gas midstream revenues		259,710			180,207			79,503			44	%
Equity earnings in equity investments		601			1,639			(1,038	)		(63	%)
Producer services and other		585			575			10			2	%

Total revenues		260,896			182,421			78,475			43	%

Expenses
Cost of gas purchased		223,762			151,657			(72,105	)		(48	%)
Operating		11,515			8,840			(2,675	)		(30	%)
General and administrative		4,984			4,706			(278	)		(6	%)
Depreciation and amortization		12,891			11,262			(1,629	)		(14	%)

Total operating expenses		253,152			176,465			(76,687	)		(43	%)

Operating income	$	7,744		$	5,956		$	1,788			30	%


Operating Statistics
Daily throughput volumes (MMcfd)		504			394			110			28	%
Gross margin	$	35,948		$	28,550		$	7,398			26	%
Cash impact of derivatives		(4,726	)		(584	)		(4,142	)		709	%

Gross margin, adjusted for impact of derivatives	$	31,222		$	27,966		$	3,256			12	%

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.

Overall, the gross margin increase was a result of higher system volumes, as well as higher NGL 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. For the comparative quarters, natural gas prices were down. Offsetting the higher volumes and commodity prices was a change in contract mix. Given our completion of certain assets in the Marcellus Shale, we gathered and transported an average of 63 MMcfd during the third quarter 2011 of fee-based volumes from these assets. This added to the mix a lower-risk, lower-margin element to our total gross margin. Gross margin from the Marcellus System in the third quarter was $7.7 million. 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, 2010. New gas volumes being added to our Panhandle system are primarily under fee-based processing percentage-of-proceeds contracts where we return the NGL revenue to the producers. The result of this is a relative volumetric decrease in the higher commodity-risked, higher-margin gas purchase/keep whole contracts; however, the performance of these contracts does suffer during periods when we experience processing capacity constraints.

We generated a significant portion 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 hedge NGLs sold and natural gas purchased. Midstream gross margin, including the cash impact of midstream derivatives, was $31.2 million compared to $28.0 million. This $3.2 million increase was primarily due to the increased system volumes, partially offset by a relative increase in lower-risk, lower-margin, percentage of proceeds and fee-based contracts (as noted above), lower margins as a result of the capacity constraints, as well as increased derivative settlements given the higher commodity prices.

Expenses

Operating expenses increased due to our expansion projects and acquisitions. The related costs of these growing or acquired facilities included increased costs of labor, chemicals, compressor rentals, and property tax.

Depreciation and amortization expenses increased primarily due to acquisitions and capital expansions in the Marcellus Shale and Panhandle systems.

Nine Months Ended September 30, 2011 Compared with Nine Months Ended September 30, 2010

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 Favorable (Unfavorable)
	2011			2010			Favorable (Unfavorable)			% Change Favorable (Unfavorable)
Financial Highlights
Revenues
Residue gas (1)	$	324,447		$	270,763		$	53,684			20	%
Natural gas liquids		345,247			199,320			145,927			73	%
Condensate		29,032			17,863			11,169			63	%
Gathering, processing and transportation fees		24,172			9,416			14,756			157	%

Total natural gas midstream revenues		722,898			497,362			225,536			45	%
Equity earnings in equity investments		2,569			4,919			(2,350	)		(48	%)
Producer services and other		2,305			1,908			397			21	%

Total revenues		727,772			504,189			223,583			44	%

Expenses
Cost of gas purchased (1)		613,295			415,111			(198,184	)		(48	%)
Operating		31,297			24,647			(6,650	)		(27	%)
General and administrative		17,549			18,357			808			4	%
Depreciation and amortization		37,379			32,638			(4,741	)		(15	%)

Total operating expenses		699,520			490,753			(208,767	)		(43	%)

Operating income	$	28,252		$	13,436		$	14,816			110	%


Operating Statistics
Daily throughput volumes (MMcfd)		462			341			121			35	%
Gross margin	$	109,603		$	82,251		$	27,352			33	%
Cash impact of derivatives		(13,628	)		(225	)		(13,403	)		(5957	%)

Gross margin, adjusted for impact of derivatives	$	95,975		$	82,026		$	13,949			17	%

(1)

For the period January 1 through June 7, 2010, we recorded $27.8 million of natural gas midstream revenues and $27.8 million for the cost of gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P (a subsidiary of Penn Virginia Corporation and considered a related party up to June 7, 2010) and the subsequent sale of that gas to third parties. We took 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 system volumes, as well as higher NGL pricing and higher frac spreads. On a year-to-date basis, natural gas prices were down for the comparative periods. Offsetting the higher volumes and frac spreads was a change in contract mix. Given our completion of certain assets in the Marcellus Shale, we gathered and transported an average of 47 MMcfd during 2011 of fee-based volumes from these assets. This added to the mix a lower-risk, lower-margin element to our total gross margin. Gross margin from the Marcellus System in the nine months was $16.6 million. 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, 2010. New gas volumes being added to our Panhandle system are primarily under fee-based processing percentage-of-proceeds contracts where we return the NGL revenue to the producers. The result of this is a relative volumetric decrease in the higher commodity-risked, higher-margin gas purchase/keep whole contracts; however, the performance of these contracts does suffer during periods when we experience processing capacity constraints.

the Panhandle region, that we have traditionally relied on to manage overruns in volumes, are fully utilized and unable to handle our excess volumes. Accordingly, we have had to forego processing a significant amount of our volumes in the Panhandle which has adversely impacted our gross margins during the third quarter. Although we have recently been able to utilize some off system processing capacity, we expect these constraints to continue through the fourth quarter and the beginning of the first quarter 2012. We have taken affirmative steps to alleviate this processing capacity constraint, including the acquisition of the Antelope Hills processing facility in June 2011, the previously announced Phase One expansion of the Antelope Hills facility from 20 mmcf/day to 80 mmcf/day, and the most recently announced Phase Two expansion of that facility to bring the processing capacity to 140 mmcf/day. Phase One is scheduled to be in service in the first quarter of 2012 and is expected to provide significant relief to our current processing capacity constraints. Phase Two is expected to be operational in the third quarter of 2012, and it will enable us to meet our expected future processing requirements as volumes continue to grow. We are also improving the connectivity between our Antelope Hills, Beaver and Sweetwater plants to enable us to better utilize our Panhandle processing capabilities and better serve the growing needs of the area producers, including those in the Granite Wash.

We generated a significant portion 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 hedge NGLs sold and natural gas purchased. Midstream gross margin, including the cash impact of midstream derivatives, was $96.0 million compared to $82.0 million. This $14.0 million increase was primarily due to the increased system volumes, partially offset by a relative increase in lower-risk, lower-margin, percentage of proceeds and fee-based contracts (as noted above), lower margins as a result of the capacity constraints, as well as increased derivative settlements given the higher commodity prices.

Expenses

Operating expenses increased due to our expansion projects and acquisitions. The related costs of these facilities included increased costs of labor, chemicals, compressor rentals, and property tax.

General and administrative expenses decreased as a result of the acceleration of recognized equity compensation in the second quarter of last year due to Penn Virginia Corporation’s divestiture of its interest in PVG. Offsetting this decrease are increased cost related to our change in management structure due to the Merger and some shared costs (such as executive and legal costs) with our former parent, Penn Virginia Corporation, are no longer shared but are now direct costs of the Partnership. Also, we have incurred more due diligence costs this year related to acquisitions.

Depreciation and amortization expenses increased primarily due to acquisitions and capital expansions in the Marcellus Shale and Panhandle systems.

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,
	2011			2010			2011			2010
Operating income	$	37,575		$	31,693		$	118,737		$	82,161
Other income (expense)
Interest expense		(10,528	)		(10,639	)		(33,806	)		(25,368	)
Derivatives		8,690			(11,020	)		(6,289	)		(11,514	)
Other		120			111			384			654

Net income	$	35,857		$	10,145		$	79,026		$	45,933

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	2011			2010			2011			2010
Interest on Revolver	$	(4,220	)	$	(2,889	)	$	(12,290	)	$	(9,518	)
Interest on Senior Notes		(6,188	)		(6,188	)		(18,563	)		(10,588	)
Debt issuance costs		(1,040	)		(1,633	)		(4,735	)		(4,243	)
Interest rate swaps		—			—			—			(1,090	)
Capitalized interest		920			71			1,782			71

Total interest expense	$	(10,528	)	$	(10,639	)	$	(33,806	)	$	(25,368	)

Interest expense, excluding capitalized interest, for the three and nine months ended September 30, 2011 has increased compared to the same periods in 2010. The increase is due to the issuance of the Senior Notes in April 2010 bearing an annual interest rate of 8.25%. The balance outstanding on the Revolver has increased given the acquisition and internal growth initiatives. Additionally, in connection with the Revolver amendments, $1.6 million and $0.5 million of debt issuance costs were expensed in 2011 and 2010 related to banks that are no longer part of the bank group. The increase in capitalized interest reflects the increase in internal growth projects and the related construction in progress for the Marcellus and Panhandle regions.

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,
	2011			2010			2011			2010
Interest Rate Swap realized derivative loss	$	(1,973	)	$	(303	)	$	(5,849	)	$	(1,057	)
Interest Rate Swap unrealized derivative gain (loss)		1,957			(1,851	)		5,259			(6,268	)
Interest Rate Swap other comprehensive income reclass		(42	)		(414	)		(366	)		(414	)
Natural gas midstream commodity realized derivative gain (loss)		(4,726	)		(7,868	)		(13,628	)		(3,550	)
Natural gas midstream commodity unrealized derivative gain (loss)		13,474			(584	)		8,295			(225	)

Total derivative gain (loss)	$	8,690		$	(11,020	)	$	(6,289	)	$	(11,514	)

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, 2011 and December 31, 2010, our environmental liabilities were $0.8 million and $0.9 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 PVR’s and PVG’s Annual Reports on Form 10-K for the year ended December 31, 2010 and remained unchanged as of September 30, 2011.

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.

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, decreases in commodity prices, changes in the business environment or deterioration 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, 2011, we reported a net commodity derivative liability related to our natural gas midstream segment of $7.6 million that is with four 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 payment of amounts to or collectability of amounts owed to us exists with regard to these counterparties.

For the three and nine months ended September 30, 2011, we reported a net derivative gain of $8.7 million and a net derivative loss of $5.3 million for commodity derivatives. Because we do not 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.

The following table lists our commodity derivative agreements for the period presented:


	Average Volume Per Day			Swap Price			Weighted Average Price				Fair Value at September 30, 2011
	Average Volume Per Day			Swap Price			Put		Call		Fair Value at September 30, 2011
NGL – natural gasoline collar		(gallons	)					(per gallon)
Fourth quarter 2011		95,000					$	1.57	$	1.94	$	(2,492	)
NGL – natural gasoline collar		(gallons	)					(per gallon)
First quarter 2012 through fourth quarter 2012		54,000					$	1.75	$	2.02		(3,138	)
Crude oil collar		(barrels	)					(per barrel)
Fourth quarter 2011		400					$	75.00	$	98.50		109
Crude oil swap		(barrels	)		(per barrel	)
First quarter 2012 through fourth quarter 2012		600		$	88.62							1,604
Natural gas purchase swap		(MMBtu	)		(MMBtu	)
Fourth quarter 2011		6,500		$	5.80							(1,193	)
Natural gas purchase swap		(MMBtu	)		(MMBtu	)
First quarter 2012 through fourth quarter 2012		4,000		$	5.195							(1,370	)
Settlements to be paid in subsequent period												(1,165	)

											$	(7,645	)

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 $1.2 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 $1.2 million. We estimate that a $1.00 per MMBtu increase in the natural gas price would increase the fair value of our natural gas purchase swaps by $1.9 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 $1.9 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 $2.5 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 $2.5 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 2011 would increase or decrease by $3.4 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 2011 would increase or decrease by $0.1 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, 2011, we had $635.0 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 September 2011 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million, or 39% of our outstanding indebtedness under the Revolver as of September 30, 2011, with us paying a weighted average fixed rate of 3.37% on the notional amount, and the counterparties paying a variable

rate equal to the three-month LIBOR. From December 2011 to December 2012, the notional amounts of the Interest Rate Swaps total $100.0 million, or 16% of our outstanding indebtedness under the Revolver as of September 30, 2011, 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. 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, 2011 would cost us approximately $3.9 million in additional interest expense per year.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. Approximately 84%, or $98.4 million, of our consolidated accounts receivable at September 30, 2011 resulted from our natural gas midstream segment and approximately 16%, or $18.2 million, resulted from our coal and natural resource management segment. Approximately $40.5 million of the natural gas midstream segment’s receivables at September 30, 2011 related to four customers, Conoco Phillips Company, Tenaska Marketing Ventures, Targa Liquids Marketing and Trade and Williams NGL Marketing, LLC. At September 30, 2011, 41% of our natural gas midstream segment accounts receivable and 35% of our consolidated accounts receivable related to these natural gas midstream customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these 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, 2011, no receivables were collateralized, and we had a $0.3 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, 2011. 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, 2011, 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.

Part I, Item 1A, of the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 24, 2011, includes a detailed discussion of the Partnership’s risk factors. The information below provides updates to the previously disclosed risk factors and when read in conjunction with the risk factors and information disclosed in the Partnership’s 2010 Annual Report on Form 10-K represent our currently known material risks.

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

Mine operators, including our lessees, must obtain numerous permits and approvals that impose strict conditions and obligations relating to various environmental and safety matters in connection with coal mining. The permitting rules, and the interpretations of these rules are complex, change frequently, and are often subject to discretionary interpretations by regulators, all of which may make compliance more difficult, and may possibly preclude the continuance of ongoing mining operations or the development of future mining operations.

To dispose of mining overburden generated from surface mining activities, our lessees often need to obtain government approvals, including CWA Section 404 permits to construct valley fills, stream impoundments, and sediment control ponds. Recently, these Section 404 permits and the Section 404 permitting standard have been the target of increased scrutiny by environmental groups, legislators, the White House, and the EPA which has made it more difficult for miners to obtain, and in some cases maintain, Section 404 permits. In some cases, the EPA is retroactively rescinding permits that have been issued. The U.S. Office of Surface Mining and Reclamation is in the process of rewriting the “stream buffer zone rule” which currently requires surface mining operators to minimize soil disturbances and dispose of excess mining spoil away from water sources. If the EPA promulgates a more restrictive stream buffer zone rule, any such additional requirements could impact coal mining operations, particularly in Appalachia, including, for example, by reducing locations where coal mining operations can be conducted or by further restricting common spoil disposal practices. Regulations which dramatically increase the costs of compliance or prohibit our lessees from obtaining new permits could reduce coal production and cash flows, and could ultimately have an adverse effect on our royalty revenues.

Item 6

Exhibits



**10.1		Penn Virginia Resource GP, LLC Non-Employee Director Compensatory Summary Sheet *

**10.2		Employment Agreement dated October 6, 2011 by and between Penn Virginia Resource GP, LLC and William H. Shea, Jr. *

**10.3		Employment Agreement dated October 6, 2011 by and between Penn Virginia Resource GP, LLC and Robert B. Wallace. *

**10.4		Employment Agreement dated October 6, 2011 by and between Penn Virginia Resource GP, LLC and Ronald K. Page. *

**10.5		Employment Agreement dated October 6, 2011 by and between Penn Virginia Resource GP, LLC and Keith D. Horton. *

**10.6		Employment Agreement dated October 6, 2011 by and between Penn Virginia Resource GP, LLC and Bruce D. Davis, Jr. *

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.



**101		The following financial information from the quarterly report on Form 10-Q of Penn Virginia Resource Partners L.P. for the quarter ended September 31, 2011, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Income, (iii) Consolidated Statements of Cash Flows, and (iv) Notes to Consolidated Financial Statements, tagged as blocks of text.

*	Management contract or compensatory plan or arrangement.

**	Furnished herewith.

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: November 1, 2011	By:	/S/ ROBERT B. WALLACE
		Robert B. Wallace Executive Vice President and Chief Financial Officer

Date: November 1, 2011	By:	/S/ FORREST W. MCNAIR
		Forrest W. McNair Vice President and Controller