PVR Partners, L. P. (PVR) 10-Q 2009 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2009

or

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

For the transition period from                    to                    

Commission File Number: 1-16735

PENN VIRGINIA RESOURCE PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	23-3087517
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

THREE RADNOR CORPORATE CENTER, SUITE 300

100 MATSONFORD ROAD

RADNOR, PA 19087

(Address of principal executive offices) (Zip Code)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

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

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

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

As of August 5, 2009, 51,798,895 common limited partner units were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX

		Page
PART I.	Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Statements of Income for the Three and Six Months Ended June 30, 2009 and 2008	1
	Condensed Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008	2
	Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2009 and 2008	3
	Notes to Condensed Consolidated Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	16
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	32
Item 4.	Controls and Procedures	35
PART II.	Other Information	36
Item 6.	Exhibits	36

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Revenues
Natural gas midstream	$	113,060		$	234,797		$	230,439		$	359,845
Coal royalties		29,997			31,641			60,627			55,603
Coal services		1,745			1,841			3,633			3,703
Other		4,617			8,226			11,479			14,168
Total revenues		149,419			276,505			306,178			433,319
Expenses
Cost of midstream gas purchased		92,154			202,819			192,774			302,516
Operating		9,018			8,719			17,908			15,512
Taxes other than income		980			976			2,203			2,048
General and administrative		8,257			6,743			15,853			13,261
Depreciation, depletion and amortization		17,617			12,919			34,120			24,419
Total expenses		128,026			232,176			262,858			357,756
Operating income		21,393			44,329			43,320			75,563
Other income (expense)
Interest expense		(6,365	)		(5,374	)		(11,981	)		(10,306	)
Other		328			458			646			920
Derivatives		(2,034	)		(29,942	)		(9,195	)		(22,166	)
Net income	$	13,322		$	9,471		$	22,790		$	44,011
General partner’s interest in net income	$	6,181		$	5,607		$	12,285		$	10,677
Limited partners’ interest in net income	$	7,141		$	3,864		$	10,505		$	33,334
Basic and diluted net income per limited partner unit (see Note 6)	$	0.13		$	0.08		$	0.20		$	0.70
Weighted average number of units outstanding, basic and diluted		51,799			48,581			51,799			47,521

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

1

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)

	June 30, 2009			December 31, 2008
Assets
Current assets
Cash and cash equivalents	$	7,481		$	9,484
Accounts receivable, net of allowance for doubtful accounts		62,448			73,267
Derivative assets		11,478			30,431
Other current assets		4,668			4,263
Total current assets		86,075			117,445
Property, plant and equipment		1,121,838			1,093,526
Accumulated depreciation, depletion and amortization		(228,894	)		(198,407	)
Net property, plant and equipment		892,944			895,119
Equity investments		79,512			78,442
Intangible assets, net		88,962			92,672
Other long-term assets		42,651			35,141
Total assets	$	1,190,144		$	1,218,819
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	49,804		$	60,390
Accrued liabilities		8,826			10,796
Deferred income		2,987			4,842
Derivative liabilities		12,278			13,585
Total current liabilities		73,895			89,613
Deferred income		5,662			6,150
Other liabilities		16,585			17,359
Derivative liabilities		3,949			6,915
Long-term debt		597,100			568,100
Partners’ capital		492,953			530,682
Total liabilities and partners’ capital	$	1,190,144		$	1,218,819

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

2

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Cash flows from operating activities
Net income	$	13,322		$	9,471		$	22,790		$	44,011
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		17,617			12,919			34,120			24,419
Commodity derivative contracts:
Total derivative losses		2,951			31,459			10,566			24,791
Cash settlements of derivatives		1,613			(9,703	)		4,449			(19,225	)
Non-cash interest expense		1,242			204			1,733			368
Equity earnings, net of distributions received		488			354			(1,071	)		(6	)
Other		(335	)		(312	)		(630	)		(621	)
Changes in operating assets and liabilities		2,287			89			1,601			(410	)
Net cash provided by operating activities		39,185			44,481			73,558			73,327
Cash flows from investing activities
Acquisitions		(606	)		(96,220	)		(1,862	)		(96,240	)
Additions to property, plant and equipment		(15,208	)		(21,190	)		(32,258	)		(38,840	)
Other		307			334			572			675
Net cash used in investing activities		(15,507	)		(117,076	)		(33,548	)		(134,405	)
Cash flows from financing activities
Distributions to partners		(30,878	)		(25,640	)		(61,755	)		(50,358	)
Proceeds from borrowings		14,000			99,800			41,000			124,800
Repayments of borrowings		(12,000	)		(132,400	)		(12,000	)		(155,400	)
Net proceeds from issuance of partners’ capital		—			140,958			—			140,958
Other		—			(620	)		(9,258	)		(620	)
Net cash provided by (used in) operating activities		(28,878	)		82,098			(42,013	)		59,380
Net increase (decrease) in cash and cash equivalents		(5,200	)		9,503			(2,003	)		(1,698	)
Cash and cash equivalents – beginning of period		12,681			8,329			9,484			19,530
Cash and cash equivalents – end of period	$	7,481		$	17,832		$	7,481		$	17,832
Supplemental disclosure:
Cash paid for interest	$	5,846		$	4,249		$	12,002		$	10,372

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

3

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

June 30, 2009

1. Organization

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

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded Delaware limited partnership. At June 30, 2009, Penn Virginia owned an approximately 77% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At June 30, 2009, PVG owned an approximately 37% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us.

2. Basis of Presentation

Our condensed consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Investments in non-controlled entities over which we exercise significant influence are accounted for using the equity method. Intercompany balances and transactions have been eliminated in consolidation. Our condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our condensed consolidated financial statements have been included. Our condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Operating results for the three and six months ended June 30, 2009 are not necessarily indicative of the results that may be expected for the year ending December 31, 2009. Certain reclassifications have been made to conform to the current period’s presentation. In preparing the accompanying condensed consolidated financial statements, we have evaluated subsequent events through August 5, 2009.

3. Fair Value Measurements

Effective January 1, 2009, Statement of Financial Accounting Standards (“SFAS”) No. 157,Fair Value Measurements, applies to both our financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis. Our financial instruments that are subject to fair value disclosures consist of cash and cash equivalents, accounts receivable, accounts payable, derivative instruments and long-term debt. 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, 2008. At June 30, 2009, the carrying values of all of these financial instruments approximated fair value.

4

The following table summarizes the valuation of certain assets and liabilities by category as of June 30, 2009 (in thousands):

				Fair Value Measurements at June 30, 2009, Using
Description	Fair Value Measurements at June 30, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap - noncurrent	$	900		$	—	$	900		$	—
Interest rate swap liabilities - current		(6,478	)		—		(6,478	)		—
Interest rate swap liabilities - noncurrent		(3,949	)		—		(3,949	)		—
Commodity derivative assets - current		11,478			—		11,478			—
Commodity derivative liabilities - current		(5,800	)		—		(5,800	)		—
Total	$	(3,849	)	$	—	$	(3,849	)	$	—

See Note 4 – “Derivative Instruments,” for the effects of derivative instruments on our condensed consolidated financial statements.

4. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We determine the fair values of our derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities as of June 30, 2009, using discount rates adjusted for the credit risk of the 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 positions as of June 30, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

		Weighted Average Price Collars
	Average Volume Per Day	Additional Put Option		Put		Call		Fair Value (in thousands)
Crude Oil Three-Way Collar	(in barrels)				(per barrel)
Third Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	2,634
Frac Spread Collar	(in MMBtu)				(per MMBtu)
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		1,235
Crude Oil Collar	(in barrels)				(per barrel)
Second Quarter 2010 through Fourth Quarter 2010	750			$	70.00	$	81.25		28
Settlements to be received in subsequent period									1,781
Natural gas midstream segment commodity derivatives - net asset								$	5,678

See theFinancial Statement Impact of Derivativessection below for the impact of the natural gas midstream commodity derivatives on our condensed consolidated financial statements.

5

Interest Rate Swaps

We have entered into interest rate swaps (the “Interest Rate Swaps”) to establish fixed rates on a portion of the outstanding borrowings under our revolving credit facility (the “Revolver”). The following table sets forth our Interest Rate Swap positions at June 30, 2009:

Dates	Notional Amounts		Weighted-Average Fixed Rate
	(in millions)
Until March 2010	$	310.0	3.54	%
March 2010 - December 2011	$	250.0	3.37	%
December 2011 - December 2012	$	100.0	2.09	%

During the first quarter of 2009, we discontinued cash flow hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in the derivative line item of our condensed consolidated statements of income. At June 30, 2009, a $3.0 million loss remained in accumulated other comprehensive income (“AOCI”) related to these discontinued Interest Rate Swap hedges. The $3.0 million loss will be recognized in interest expense as the originally forecasted transactions settle.

We reported a (i) net derivative liability of $9.5 million at June 30, 2009 and (ii) loss in AOCI of $3.0 million at June 30, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we reclassified a total of $1.7 million of net hedging losses on the Interest Rate Swaps to interest expense during the six months ended June 30, 2009. See theFinancial Statement Impact of Derivativessection below for the impact of the Interest Rate Swaps on our condensed consolidated financial statements.

Financial Statement Impact of Derivatives

The following table summarizes the effects of our derivative activities, as well as the location of the gains and losses, on our condensed consolidated statements of income for the three and six months ended June 30, 2009 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three Months Ended June 30, 2009			Six Months Ended June 30, 2009
Derivatives de-designated as hedging instruments:
Interest rate contracts (1)	Interest expense	$	(918	)	$	(1,743	)
Decrease in net income resulting from derivatives de-designated as hedging instruments		$	(918	)	$	(1,743	)
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivatives	$	1,810		$	696
Commodity contracts	Derivatives		(3,843	)		(9,890	)
Decrease in net income resulting from derivatives not designated as hedging instruments		$	(2,033	)	$	(9,194	)
Total decrease in net income resulting from derivatives		$	(2,951	)	$	(10,937	)
Realized and unrealized derivative impact:
Cash received for commodity and interest rate contract settlements	Derivatives		1,613			4,449
Cash paid for interest rate contract settlements	Interest expense		—			(370	)
Unrealized derivative losses (2)			(4,564	)		(15,016	)
Total decrease in net income resulting from derivatives		$	(2,951	)	$	(10,937	)

(1) This represents amounts reclassified out of AOCI and into earnings. At June 30, 2009, a $3.0 million loss remained in AOCI related to Interest Rate Swaps on which we discontinued hedge accounting.

6

(2) This activity represents net unrealized gains (losses) in the natural gas midstream, cost of midstream gas purchased, interest expense and derivatives line items on our condensed consolidated statements of income. For the three months ended June 30, 2009, the net unrealized derivative losses were composed of a $2.6 million unrealized gain on our Interest Rate Swaps and a $7.2 million unrealized loss on our commodity derivatives. For the six months ended June 30, 2009, the net unrealized derivative losses were composed of a $2.0 million unrealized gain on our Interest Rates Swaps and a $17.0 million unrealized loss on our commodity derivatives.

The following table summarizes the fair value of our derivative instruments, as well as the locations of these instruments, on our condensed consolidated balance sheets as of June 30, 2009 and December 31, 2008 (in thousands):

	Balance Sheet Location	Fair values as of June 30, 2009				Fair values as of December 31, 2008
		Derivative       Assets		Derivative       Liabilities		Derivative         Assets		Derivative         Liabilities
Derivatives de-designated as hedging instruments:
Interest rate contracts	Derivative liabilities - current	$	—	$	—	$	—	$	1,228
Interest rate contracts	Derivative liabilities - noncurrent		—		—		—		1,842
Total derivatives de-designated as hedging instruments		$	—	$	—	$	—	$	3,070
Derivatives not designated as hedging instruments:
Interest rate contracts	Derivative liabilities - current	$	—	$	6,478	$	—	$	4,663
Interest rate contracts	Derivative assets/liabilities - noncurrent		900		3,949		—		5,073
Commodity contracts	Derivative assets/liabilities - current		11,478		5,800		30,431		7,694
Total derivatives not designated as hedging instruments		$	12,378	$	16,227	$	30,431	$	17,430
Total fair values of derivative instruments		$	12,378	$	16,227	$	30,431	$	20,500

See Note 3, “Fair Value Measurements,” for a description of how the above financial instruments are valued in accordance with SFAS No. 157.

The following table summarizes our interest expense for the three and six months ended June 30, 2009 and 2008, including the effect of the Interest Rate Swaps (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Source	2009			2008			2009			2008
Borrowings	$	5,596		$	4,935		$	10,464		$	10,622
Capitalized interest		(149	)		(187	)		(226	)		(675	)
Interest rate swaps		918			626			1,743			359
Total interest expense	$	6,365		$	5,374		$	11,981		$	10,306

At June 30, 2009, we reported a commodity derivative asset related to our natural gas midstream segment of $5.7 million that is with three counterparties, which are investment grade financial institutions, and is substantially concentrated with one 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. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of June 30, 2009. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

7

The above hedging activity represents cash flow hedges. As of June 30, 2009, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of June 30, 2009, we did not own derivative instruments containing credit risk contingencies.

5. Long-Term Debt

In March 2009, we increased the size of the Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs that will be amortized over the remaining life of the Revolver. The Revolver is secured with substantially all of our assets. The December 2011 maturity date for the Revolver did not change. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under the Revolver, or at a rate derived from the London Interbank Offered Rate (“LIBOR”) plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. As of June 30, 2009 and 2008, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 2.5% and 4.6%.

6. Partners’ Capital and Distributions

As of June 30, 2009, partners’ capital consisted of 51.8 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of June 30 2009, affiliates of Penn Virginia, in the aggregate, owned a 39% interest in us, consisting of 19.6 million common units and a 2% general partner interest.

Net Income per Limited Partner Unit

Emerging Issues Task Force (“EITF”) Issue No. 07-4,Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”) addresses the computation of earnings per unit for master limited partnerships that issue multiple classes of securities that participate in partnership distributions and, effective January 1, 2009, is applied retroactively to all periods presented.

Our securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (“IDRs”). EITF 07-4 requires earnings or losses for a reporting period to be allocated to the limited partner, general partner and holders of IDRs using the two-class method to compute earnings per unit. Under this method, EITF 07-4 requires net income or loss for a reporting period to be reduced (or increased) by the amount of Available Cash (as defined by our partnership agreement) that has been or will be distributed to the participating security holders. Under the partnership agreement, IDRs are not entitled to distributions other than those provided for under the definition of Available Cash. 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. Any excess of distributions over net income (or excess of net income over distributions) shall be allocated to the limited partners and general partner, 98% and 2% as specified in the partnership agreement.

Basic and diluted net income per limited partner unit is computed by dividing net income allocable to limited partners by the weighted average number of limited partnership units outstanding during the period. During the six months ended June 30, 2009, our general partner granted 354,792 phantom units. See Note 8, “Unit-Based Compensation,” for a description of phantom units. These unit-based payment awards contain rights to receive nonforfeitable distributions and are considered participating securities when computing earnings per limited partner unit. Diluted earnings per limited partner unit are computed by dividing net income allocable to limited partners by the weighted average number of limited partner units outstanding during the period and, when dilutive, phantom units. Net income allocable to limited partners is net of earnings allocated to our general partner.

We adopted Financial Accounting Standards Board (“FASB”) Staff Position No. EITF 03-6-1,Determining Whether Instruments Granted in Share-Based Payment Transactions are Participating Securities (“EITF 03-6-1”) on January 1, 2009. Under EITF 03-6-1, unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents are participating securities and, therefore, are included in the computation of both basic and diluted earnings per unit pursuant to the two-class method. The two-class method determines earnings per unit for each class of common units and participating securities according to distributions or distribution equivalents and their respective participation rights in undistributed earnings. We determined that our phantom unit awards contain non-forfeitable rights to distributions and, therefore, are participating securities as defined in EITF 03-6-1. We applied EITF 03-6-1 retroactively to all periods presented as required.

8

The following table reconciles the computation of basic and diluted weighted average limited partner units. The following amounts reflect the retroactive application of EITF 07-4 and EITF 03-6-1 on certain previously reported items for the three and six months ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
				As Adjusted						As Adjusted
Net income	$	13,322		$	9,471		$	22,790		$	44,011
Less:
Distributions payable on behalf of incentive distribution rights		(6,035	)		(5,528	)		(12,070	)		(9,997	)
Distributions payable on behalf of general partner interest		(497	)		(486	)		(994	)		(909	)
General partner interest in excess of distributions over earnings (excess of earnings over distributions) allocable to the general partner interest		351			407			779			229
Net income allocable to limited partners and participating securities	$	7,141		$	3,864		$	10,505		$	33,334
Less:
Distributions to participating securities		(167	)		—			(334	)		—
Participating securities’ allocable share of net income		(47	)		—			(69	)		—
Net income allocable to limited partners	$	6,927		$	3,864		$	10,102		$	33,334
Weighted average limited partner units, basic and diluted		51,799			48,581			51,799			47,521
Net income per limited partner, basic	$	0.13		$	0.08		$	0.20		$	0.70
Net income per limited partner, diluted	$	0.13		$	0.08		$	0.20		$	0.70

For the three and six months ended June 30, 2009, awards for 88,000 and 75,000 average units, respectively, of participating securities were excluded from the diluted earnings per unit calculation because the inclusion of these units would have had an anti-dilutive effect.

Cash Distributions

We distribute 100% of Available Cash within 45 days after the end of each quarter to unitholders of record and to our general partner. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements and (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.

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

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

9

The following table reflects the allocation of total cash distributions paid by us during the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008
	(in thousands, except per unit data)				(in thousands, except per unit data)
Limited partner units	$	24,345	$	20,748	$	48,690	$	41,035
General partner interest (2%)		497		423		994		837
Incentive distribution rights		6,035		4,469		12,070		8,486
Total cash distributions paid	$	30,877	$	25,640	$	61,754	$	50,358
Total cash distributions paid per limited partner unit	$	0.47	$	0.45	$	0.94	$	0.89

On August 14, 2009, we will pay a $0.47 per unit quarterly distribution to unitholders of record on August 3, 2009. This per unit distribution will remain unchanged from the previous distribution paid on May 15, 2009.

7. Related-Party Transactions

General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us and our subsidiaries totaled $1.6 million for both the three months ended June 30, 2009 and 2008 and $3.1 million for both the six months ended June 30, 2009 and 2008. These costs are reflected in the general and administrative expense line item on our condensed consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable.

Accounts Payable—Affiliate

Amounts payable to related parties totaled $8.0 million as of June 30, 2009 and December 31, 2008. These amounts are primarily due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (“PVOG LP”) and are related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (“PVR East Texas”) and PVOG LP. See – “Gathering and Processing Revenues.” These balances are included in the accounts payable line item on our condensed consolidated balance sheets.

Marketing Revenues

PVOG LP and Connect Energy Services, LLC (“Connect Energy”), our wholly owned subsidiary, are parties to a Master Services Agreement. PVOG LP and Connect Energy have agreed that Connect Energy will market all of PVOG LP’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG LP for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one-year terms until terminated by either party. Under the Master Services Agreement, PVOG LP paid fees to Connect Energy of $0.4 million and $0.8 million for the three months ended June 30, 2009 and 2008 and $0.8 million and $1.5 million for the six months ended June 30, 2009 and 2008. Marketing revenues are included in the other revenues line item on our condensed consolidated statements of income.

10

Gathering and Processing Revenues

PVR East Texas and PVOG LP are parties to a natural Gas Gathering and Processing Agreement under which PVOG LP and PVR East Texas have agreed that PVR East Texas will gather and process all of PVOG LP’s current and future gas production in certain areas of the Bethany Field in East Texas and redeliver the natural gas liquids (“NGLs”) to PVOG LP for a $0.30 per MMBtu service fee (with an annual CPI adjustment). The Gas Gathering and Processing Agreement has a primary term of 15 years and automatically renews for additional one-year terms until terminated by either party. PVR East Texas began gathering and processing PVOG LP’s gas in June 2008. Pursuant to the Gas Gathering and Processing Agreement, PVOG LP paid PVR East Texas $1.2 million and $0.7 million in fees for the three months ended June 30, 2009 and 2008 and $2.1 million and $0.7 million in fees for the six months ended June 30, 2009 and 2008. These gathering and processing revenues are recorded in the natural gas midstream line on our condensed consolidated statements of income.

From time to time, PVOG LP sells gas or NGLs to Connect Energy at our Crossroads plant and Connect Energy transports them to the marketing location and then resells them to third parties. The sales price received by PVOG LP from Connect Energy for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. PVOG LP received from Connect Energy $20.0 million and $49.8 million in connection with such sales for the three months ended June 30, 2009 and 2008 and $41.2 million and $49.8 million in connection with such sales for the six months ended June 30, 2009 and 2008.

In the three months ended June 30, 2009 and 2008, we recorded $20.0 million and $49.8 million of natural gas midstream revenue and $20.0 million and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. In the six months ended June 30, 2009 and 2008, we recorded $41.2 million and $49.8 million of natural gas midstream revenue and $41.2 million and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas and NGLs prior to transporting them to third parties. These transactions do not impact our gross margin, nor do they impact operating income other than the processing and marketing fee noted above.

8. Unit-Based Compensation

The Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (“LTIP”) permits the grant of phantom units to employees and directors. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit, or in the discretion of the Compensation and Benefits Committee of our general partner’s board of directors, the cash equivalent of the value of a common unit. In addition, all phantom units will vest upon a change of control.

We recognized a total of $1.3 million and $0.7 million for the three months ended June 30, 2009 and 2008 and $2.7 million and $1.5 million for the six months ended June 30, 2009 and 2008 of compensation expense related to the vesting of restricted and phantom units and the granting of common and deferred common units under our LTIP. During the six months ended June 30, 2009, our general partner granted 354,792 phantom units with a weighted average grant date fair value of $11.59 per unit to employees of Penn Virginia and its affiliates. The phantom units granted in 2009 vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period. These expenses are recorded in the general and administrative expense line on our condensed consolidated statements of income.

9. Comprehensive Income

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income.

11

The following table sets forth the components of comprehensive income for the three and six months ended June 30, 2009 and 2008:

	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009			2008
	(in thousands)				(in thousands)
Net income	$	13,322	$	9,471	$	22,790		$	44,011
Unrealized holding gains (losses) on derivative activities		—		4,318		(506	)		(825	)
Reclassification adjustment for derivative activities		915		2,143		1,740			2,984
Comprehensive income	$	14,237	$	15,932	$	24,024		$	46,170

10. Commitments and Contingencies

Legal

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

Environmental Compliance

As of June 30, 2009 and December 31, 2008, our environmental liabilities were $1.1 million and $1.2 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

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

Customer Credit Risk

For the six months ended June 30, 2009, two of our natural gas midstream segment customers accounted for $56.3 million and $35.6 million, or 18% and 12%, of our total consolidated revenues. At June 30, 2009, 20% of our consolidated accounts receivable related to these customers.

11. Segment Information

Our reportable segments are as follows:

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

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

12

The following tables present a summary of certain financial information relating to our segments as of and for the three months ended June 30, 2009 and 2008 (in thousands):

	Revenues				Operating income (loss)
	Three Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009			2008
Coal and natural resource management	$	35,144	$	39,056	$	20,333		$	23,983
Natural gas midstream		114,275		237,449		1,060			20,346
Consolidated totals	$	149,419	$	276,505	$	21,393		$	44,329
Interest expense						(6,365	)		(5,374	)
Other						328			458
Derivatives						(2,034	)		(29,942	)
Consolidated net income					$	13,322		$	9,471
	Additions to property and equipment				DD&A expense
	Three Months Ended June 30,				Three Months Ended June 30,
	2009		2008		2009			2008
Coal and natural resource management	$	606	$	24,641	$	8,164		$	7,526
Natural gas midstream		15,208		92,769		9,453			5,393
Consolidated totals	$	15,814	$	117,410	$	17,617		$	12,919
	Total assets at
	June 30, 2009		December 31, 2008
Coal and natural resource management	$	594,491	$	600,418
Natural gas midstream		595,653		618,401
Consolidated totals	$	1,190,144	$	1,218,819

13

The following tables present a summary of certain financial information relating to our segments as of and for the six months ended June 30, 2009 and 2008 (in thousands):

	Revenues				Operating income (loss)
	Six Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009			2008
Coal and natural resource management	$	73,396	$	69,350	$	45,307		$	41,565
Natural gas midstream		232,782		363,969		(1,987	)		33,998
Consolidated totals	$	306,178	$	433,319	$	43,320		$	75,563
Interest expense						(11,981	)		(10,306	)
Other						646			920
Derivatives						(9,195	)		(22,166	)
Consolidated net income					$	22,790		$	44,011
	Additions to property and equipment				DD&A expense
	Six Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009			2008
Coal and natural resource management	$	1,906	$	24,689	$	15,558		$	13,939
Natural gas midstream		32,214		110,391		18,562			10,480
Consolidated totals	$	34,120	$	135,080	$	34,120		$	24,419
	Total assets at
	June 30, 2009		December 31, 2008
Coal and natural resource management	$	594,491	$	600,418
Natural gas midstream		595,653		618,401
Consolidated totals	$	1,190,144	$	1,218,819

12. New Accounting Standards

In June 2008, the FASB issued Staff Position EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities. EITF 03-6-1 provides that unvested unit-based payment awards that contain non-forfeitable rights to distributions or distribution equivalents, whether paid or unpaid, are participating securities and, therefore, are included in the computation of both basic and diluted earnings per unit. EITF 03-6-1 is effective for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. Early application was not permitted. We adopted EITF 03-6-1 effective January 1, 2009, and there was no material impact on our financial statements as a result of this adoption.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1,Interim Disclosures About Fair Value of Financial Instruments, which requires disclosures about the fair value of financial instruments whenever we issue financial statements. The disclosures outlined in FSP FAS 107-1 and APB 28-1 are required for interim and annual periods ending after June 15, 2009. Early adoption is permitted for periods ending after March 15, 2009, and we adopted FSP FAS 107-1 and APB 28-1 as of March 31, 2009. Disclosures for earlier periods presented for comparative purposes at initial adoption are not required.

In April 2009, the FASB issued FSP FAS 141(R)-1,Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies, which requires us to recognize assets acquired or liabilities assumed in a business combination that arise from a contingency if the acquisition-date fair value of that asset or liability can be determined during the measurement period. If the acquisition-date fair value of an asset acquired or a liability assumed in a business combination that arises from a contingency cannot be determined during the measurement period, we are required to recognize an asset or liability at the time of the acquisition at the amount that would be recognized in accordance with SFAS No. 5,Accounting for Contingencies and FASB Interpretation No. 14,Reasonable Estimation of the Amount of a Loss—an interpretation of FASB Statement No. 5. FSP FAS 141(R)-1 is effective for assets or liabilities arising from contingencies in business combinations for which the acquisition date is on or after

14

December 15, 2008. We have had no material acquisitions since our adoption of FSP FAS 141(R)-1. For each acquisition that includes assets acquired or liabilities assumed arising from contingencies, we will determine the fair value of the assets or liabilities and will make the appropriate disclosures.

In April 2009, the FASB issued FSP FAS 157-4,Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly, which provides additional guidance for estimating fair value in accordance with FASB Statement No. 157,Fair Value Measurements, when the volume and activity level for an asset or liability have significantly decreased and when transactions are not orderly (i.e. distressed or forced), since quoted prices may not be determinative of fair value. In such cases, FSP FAS 157-4 requires further analysis of the transactions or quoted prices to determine whether a significant adjustment to the transactions or quoted prices, using a valuation technique other than the quoted price, is necessary to estimate fair value in accordance with Statement No. 157. FSP FAS 157-4 amends Statement No. 157 and requires disclosure in interim and annual periods of the inputs and valuation techniques used, a discussion of changes in valuation techniques and related inputs, if any, and definition of major categories for equity securities and debt securities. We adopted FSP FAS 157-4 effective June 30, 2009, and there was no impact on our financial statements as a result of this adoption. Further, we do not expect the standard to have a material impact on our financial statements unless future fair value measurements are affected by inactive markets.

In May 2009, the FASB issued Statement No.165,Subsequent Events, which establishes recognition and disclosure requirements for events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Statement No. 165 requires entities to disclose the date through which subsequent events have been evaluated, as well as whether that date is the date the financial statements were issued or the date the financial statements were available to be issued. We adopted Statement No. 165 effective June 30, 2009, and there was no material impact on our financial statements as a result of this adoption.

In June 2009, the FASB issued SFAS No. 168,The FASB Accounting StandardsCodification^TM and the Hierarchy of Generally Accepted Accounting Principles, which replaces SFAS No. 162,The Hierarchy of Generally Accepted Accounting Principles. SFAS No. 168 will become the source of authoritative U.S. generally accepted accounting principles recognized by the FASB to be applied by nongovernmental entities and is effective for financial statements issued for interim and annual periods ending after September 15, 2009. We do not anticipate any material impact on our financial statements as a result of adopting SFAS No. 168 other than changes in reference from specific accounting standards to accounting standards codification references, and will adopt it effective September 30, 2009.

13. Subsequent Events

On July 13, 2009, our natural gas midstream business completed an acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million in cash. Funding for the acquisition was provided by borrowings under the Revolver. The acquired assets consist of a 60 MMcf per day processing plant within Atlas’ 180 MMcf per day Sweetwater facility. We expect the facility to be processing our gas by the end of August 2009 after system connections and field compression are installed at an additional cost of approximately $5.0 million. Additionally, a recently completed 40 MMcf per day processing plant expansion in our Beaver/Spearman complex (the “Panhandle System”) was in service at July 31, 2009.

The acquired and expanded processing facilities will increase our processing capacity in the Panhandle System to 260 MMcf per day and overall processing capacity to 400 MMcf per day. The increased processing capacity will allow us to process gas volumes of approximately 50 MMcf per day which were being bypassed due to processing capacity constraints in the Panhandle System and will alleviate pipeline pressure-related volume constraints in the eastern portion of the Panhandle System.

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

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

Overview of Business

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

Selected Financial Data – Consolidated

Summary operating results for the three and six months ended June 30, 2009 and 2008 were as follows (in thousands):

	Three Months Ended June 30,								Six Months Ended June 30,
	2009			2008			% Change		2009			2008			% Change
Revenues	$	149,419		$	276,505		(46	%)	$	306,178		$	433,319		(29	%)
Expenses		128,026			232,176		(45	%)		262,858			357,756		(27	%)
Operating income		21,393			44,329		(52	%)		43,320			75,563		(43	%)
Other income (expense)		(8,071	)		(34,858	)	(77	%)		(20,530	)		(31,552	)	(35	%)
Net income	$	13,322		$	9,471		41	%	$	22,790		$	44,011		(48	%)

We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream.

• Coal and Natural Resource Management—management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber; leasing of fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants; collection of oil and gas royalties; and coal transportation, or wheelage, fees. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882.

• Natural Gas Midstream—natural gas processing, gathering and other related services. We entered this business segment in 2005.

16

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

	Coal and Natural Resource Management		Natural Gas Midstream			Consolidated
	(in thousands)
For the Six Months Ended June 30, 2009:
Revenues	$	73,396	$	232,782		$	306,178
Cost of midstream gas purchased		—		192,774			192,774
Operating costs and expenses		12,531		23,433			35,964
Depreciation, depletion and amortization		15,558		18,562			34,120
Operating income (loss)	$	45,307	$	(1,987	)	$	43,320
For the Six Months Ended June 30, 2008:
Revenues	$	69,350	$	363,969		$	433,319
Cost of midstream gas purchased		—		302,516			302,516
Operating costs and expenses		13,846		16,975			30,821
Depreciation, depletion and amortization		13,939		10,480			24,419
Operating income	$	41,565	$	33,998		$	75,563

Results of Operations

Coal and Natural Resource Management Segment

As of December 31, 2008, we owned or controlled approximately 827 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In the six months ended June 30, 2009, our lessees produced 17.5 million tons of coal from our properties and paid us coal royalties revenues of $60.6 million, for an average royalty per ton of $3.47 ($3.31 per ton net of coal royalties expense). Approximately 82% of our coal royalties revenues in the six months ended June 30, 2009 were derived from coal mined on our properties under leases containing royalty rates based on the higher of a fixed base price or a percentage of the gross sales price. The balance of our coal royalties revenues for the respective periods was derived from coal mined on our properties under leases containing fixed royalty rates that escalate annually.

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.

The deterioration of the global economy, including financial and credit markets, has reduced worldwide demand for coal with resultant price declines. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely affect production and pricing for coal mined by our lessees, and, consequently, adversely affect the royalty income received by us and our ability to make cash distributions to our limited partners and to Penn Virginia GP Holdings, L.P., or PVG, the owner of our general partner. The deterioration of the global economy has also adversely affected credit availability and our access to new capital. This limited access to capital and credit availability has and could continue to hamper our ability to fund acquisitions, potentially restricting future growth potential.

17

Three Months Ended June 30, 2009 Compared With the Three Months Ended June 30, 2008

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the three months ended June 30, 2009 and 2008:

	Three Months Ended June 30,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	29,997		$	31,641		(5	%)
Coal services		1,745			1,841		(5	%)
Timber		1,456			1,833		(21	%)
Oil and gas royalty		545			1,556		(65	%)
Other		1,401			2,185		(36	%)
Total revenues		35,144			39,056		(10	%)
Expenses
Coal royalties		1,569			3,397		(54	%)
Other operating		758			505		50	%
Taxes other than income		300			371		(19	%)
General and administrative		4,020			3,274		23	%
Depreciation, depletion and amortization		8,164			7,526		8	%
Total expenses		14,811			15,073		(2	%)
Operating income	$	20,333		$	23,983		(15	%)
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,739			8,839		(1	%)
Coal royalties revenue, net of coal royalties expense	$	28,428		$	28,244		1	%
Average coal royalties revenues per ton ($/ton)	$	3.43		$	3.58		(4	%)
Less coal royalties expense per ton ($/ton)		(0.18	)		(0.38	)	(53	%)
Average net coal royalties per ton ($/ton)	$	3.25		$	3.20		2	%

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended June 30, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended June 30,		Three Months Ended June 30,						Three Months Ended June 30,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,650	5,144	$	21,192		$	24,450		$	4.56		$	4.75
Northern Appalachia	1,060	1,110		1,949			1,857			1.84			1.67
Illinois Basin	1,145	1,119		2,862			2,312			2.50			2.07
San Juan Basin	1,884	1,466		3,994			3,022			2.12			2.06
Total	8,739	8,839	$	29,997		$	31,641		$	3.43		$	3.58
Less coal royalties expense (1)				(1,569	)		(3,397	)		(0.18	)		(0.38	)
Net coal royalties revenues			$	28,428		$	28,244		$	3.25		$	3.20

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

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Production. Coal production in the Northern Appalachian and Illinois Basin regions remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. Coal production in the Central Appalachian region decreased by 0.4 million tons, or 10%, from 5.1 million tons in the three months ended June 30, 2008 to 4.7 million tons in the same period of 2009. While the decrease in production primarily resulted from production cut backs due to a depressed coal market, the impact of the decreased coal production on net coal royalties revenue was not significant since a large part of the decrease was from subleased properties in Central Appalachia, from which we make lower net average royalties per ton produced than we make in other regions where coal production increased or did not decrease. Coal production in the San Juan Basin region increased by 0.4 million tons, or 29%, from 1.5 million tons in the three months ended June 30, 2008 to 1.9 million tons in the same period of 2009. This increase was primarily due to the start up of a new mine in the later part of 2008.

Revenues. Net coal royalties revenues increased slightly from $28.2 million in the three months ended June 30, 2008 to $28.4 million in the same period of 2009, driven by a $0.05 per ton increase in average coal royalties per ton, offset by a slight volume decrease. The average net coal royalty per ton, which represents the average coal royalties revenue per ton net of coal royalties expense, increased slightly from $3.20 per ton in the three months ended June 30, 2008 to $3.25 per ton in the same period of 2009.

Coal services revenues remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 21%, from $1.8 million in the three months ended June 30, 2008 to $1.5 million in the same period of 2009 primarily due to decreased sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $1.1 million, or 65%, from $1.6 million in the three months ended June 30, 2008 to $0.5 million in the same period of 2009 primarily due to decreased natural gas prices. Other revenues decreased by $0.8 million, or 36%, from $2.2 million in the three months ended June 30, 2008 to $1.4 million in the same period of 2009 primarily due to decreased wheelage income.

Expenses. Other operating expenses increased by $0.3 million, or 50%, from $0.5 million in the three months ended June 30, 2008 to $0.8 million in the same period of 2009 primarily due to an increase in expenses related to our timber operations and costs incurred under our contractual obligations for mine maintenance. Taxes other than income and depreciation, depletion and amortization expenses remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. General and administrative costs increased by $0.7 million, or 23%, from $3.3 million in the three months ended June 30, 2008 to $4.0 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs.

19

Six Months Ended June 30, 2009 Compared With the Six Months Ended June 30, 2008

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 six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,
	2009			2008			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	60,627		$	55,603		9	%
Coal services		3,633			3,703		(2	%)
Timber		2,773			3,417		(19	%)
Oil and gas royalty		1,248			2,790		(55	%)
Other		5,115			3,837		33	%
Total revenues		73,396			69,350		6	%
Expenses
Coal royalties		2,793			5,909		(53	%)
Other operating		1,641			736		123	%
Taxes other than income		725			742		(2	%)
General and administrative		7,372			6,459		14	%
Depreciation, depletion and amortization		15,558			13,939		12	%
Total expenses		28,089			27,785		1	%
Operating income	$	45,307		$	41,565		9	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		17,487			16,479		6	%
Coal royalties revenue, net of coal royalties expense	$	57,834		$	49,694		16	%
Average coal royalties revenues per ton ($/ton)	$	3.47		$	3.37		3	%
Less coal royalties expense per ton ($/ton)		(0.16	)		(0.36	)	(56	%)
Average net coal royalties per ton ($/ton)	$	3.31		$	3.01		10	%

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the six months ended June 30, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Six Months Ended June 30,		Six Months Ended June 30,						Six Months Ended June 30,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	9,308	9,955	$	42,875		$	43,029		$	4.61		$	4.32
Northern Appalachia	2,117	1,784		3,900			2,991			1.84			1.68
Illinois Basin	2,406	2,152		6,103			4,250			2.54			1.97
San Juan Basin	3,656	2,588		7,749			5,333			2.12			2.06
Total	17,487	16,479	$	60,627		$	55,603		$	3.47		$	3.37
Less coal royalties expense (1)				(2,793	)		(5,909	)		(0.16	)		(0.36	)
Net coal royalties revenues			$	57,834		$	49,694		$	3.31		$	3.01

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

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Production. Coal production in the Central Appalachian region decreased by 0.7 million tons, or 7%, from 10.0 million tons in the six months ended June 30, 2008 to 9.3 million tons in the same period of 2009. This decrease in production primarily resulted from depleted reserve areas and production cut backs due to a depressed coal market. Most of this reduction occurred on subleased properties in Central Appalachia, from which we make lower margins per ton produced than we do in other regions. Coal production in the Northern Appalachian region increased by 0.3 million tons, or 19%, from 1.8 million tons in the six months ended June 30, 2008 to 2.1 million tons in the same period of 2009. This increase was primarily due to increased longwall production from one of our lessees who encountered adverse mining conditions in the first half of 2008. Coal production in the Illinois Basin region increased by 0.2 million tons, or 12%, from 2.2 million tons in the six months ended June 30, 2008 to 2.4 million tons in the same period of 2009. This increase was primarily due to improved mining conditions encountered by our lessee in southern Illinois. Coal production in the San Juan region increased by 1.1 million tons, or 41%, from 2.6 million tons in the six months ended June 30, 2008 to 3.7 million tons in the same period of 2009. This increase was primarily due to the start up of a new mine in the later part of 2008.

Revenues. Net coal royalties revenues increased by $8.1 million, or 16%, from $49.7 million in the six months ended June 30, 2008 to $57.8 million in the same period of 2009. This increase was attributable to increases in both production and average coal sales prices. The average net coal royalty per ton, which represents the average coal royalties revenue per ton net of coal royalties expense, increased by $0.30 per ton, or 10%, from $3.01 per ton in the six months ended June 30, 2008 to $3.31 per ton in the same period of 2009 and is attributable to both the increase in the average coal royalties revenue per ton for all regions and decreased royalties expense caused by decreased production from certain subleased properties.

Coal services revenues remained relatively constant from the six months ended June 30, 2008 to the same period of 2009. Timber revenues decreased by $0.6 million, or 19%, from $3.4 million in the six months ended June 30, 2008 to $2.8 million in the same period of 2009 primarily due to decreased sales prices resulting from weakened market conditions for furniture-grade wood products. Oil and gas royalties revenues decreased by $1.6 million, or 55%, from $2.8 million in the six months ended June 30, 2008 to $1.2 million in the same period of 2009 primarily due to decreased natural gas prices. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $1.3 million, or 33%, from $3.8 million in the six months ended June 30, 2008 to $5.1 million in the same period of 2009 primarily due to increased wheelage income.

Expenses. Other operating expenses increased by $0.9 million, or 123%, from $0.7 million in the six months ended June 30, 2008 to $1.6 million in the same period of 2009 primarily due an increase in expenses related to our timber operations and costs incurred under our contractual obligations for mine maintenance. Taxes other than income remained relatively constant from the six months ended June 30, 2008 to the same period of 2009. General and administrative costs increased by $0.9 million, or 14%, from $6.5 million in the six months ended June 30, 2008 to $7.4 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs. Depreciation, depletion and amortization expenses increased by $1.7 million, or 12%, from $13.9 million in the six months ended June 30, 2008 to $15.6 million in the same period of 2009 primarily due to increased depletion expenses for our mining and timber operations.

Natural Gas Midstream Segment

Our natural gas midstream segment provides natural gas processing, gathering and other related services. As of June 30, 2009, we owned and operated natural gas midstream assets located in Oklahoma and Texas, including five natural gas processing facilities having 300 MMcfd of total capacity and approximately 4,069 miles of natural gas gathering pipelines. Our natural gas midstream business earns revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC, or Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

For the six months ended June 30, 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 63.6 Bcf, or approximately 352 MMcfd. For the six months ended June 30, 2009, 24% and 15% of our natural gas midstream segment’s revenues and 18% and 12% of our total consolidated revenues were derived from two of our natural gas midstream segment’s customers, Conoco, Inc. and Tenaska Marketing Ventures.

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We continually seek new supplies of natural gas to offset the natural declines in production from the wells currently connected to our systems and to increase system throughput volumes. New natural gas supplies are obtained for all of our systems by contracting for production from new wells, connecting new wells drilled on dedicated acreage and contracting for natural gas that has been released from competitors’ systems. In the six months ended June 30, 2009, our natural gas midstream segment made aggregate capital expenditures of $26.2 million, primarily related to our Beaver/Spearman complex, or the Panhandle System, in Texas and Oklahoma.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing natural gas liquid, or NGL, and natural gas prices. 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. The deterioration of the global economy has resulted in a decrease in demand for natural gas and NGLs. Depending on the longevity and ultimate severity of the deterioration, NGL production from our processing plants could decrease and adversely affect our natural gas midstream processing income and our ability to make cash distributions. The deterioration of the global economy has also adversely affected credit availability and our access to new capital. This limited access to capital and credit availability has and could continue to hamper our ability to fund acquisitions, potentially restricting future growth potential.

22

Three Months Ended June 30, 2009 Compared With the Three Months Ended June 30, 2008

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the three months ended June 30, 2009 and 2008:

	Three Months Ended June 30,					% Change
	2009		2008
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	67,170	$	153,537		(56	%)
Natural gas liquids		38,917		70,507		(45	%)
Condensate		3,945		8,452		(53	%)
Gathering, processing and transportation fees		3,028		2,301		32	%
Total natural gas midstream revenues (1)		113,060		234,797		(52	%)
Equity earnings in equity investment		629		556		13	%
Producer services		586		2,096		(72	%)
Total revenues		114,275		237,449		(52	%)
Expenses
Cost of midstream gas purchased (1)		92,154		202,819		(55	%)
Operating		6,691		4,817		39	%
Taxes other than income		680		605		12	%
General and administrative		4,237		3,469		22	%
Depreciation and amortization		9,453		5,393		75	%
Total operating expenses		113,215		217,103		(48	%)
Operating income	$	1,060	$	20,346		(95	%)
Operating Statistics
System throughput volumes (MMcf)		31,342		23,884		31	%
Daily throughput volumes (MMcfd)		344		262		31	%
Gross margin	$	20,906	$	31,978		(35	%)
Cash impact of derivatives		3,377		(8,186	)	141	%
Gross margin, adjusted for impact of derivatives	$	24,283	$	23,792		2	%
Gross margin ($/Mcf)	$	0.67	$	1.34		(50	%)
Cash impact of derivatives ($/Mcf)		0.10		(0.34	)	129	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.77	$	1.00		(23	%)

(1) In the three months ended June 30, 2009, we recorded $20.0 million of natural gas midstream revenue and $20.0 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P., or PVOG LP, and the subsequent sale of that gas to third parties. We take title to the gas prior to transporting it to third parties. These transactions do not impact our gross margin.

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

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The 35% gross margin decrease in the three months ended June 30, 2009 as compared to the same period of 2008 was primarily due to decreased commodity pricing and 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. The gross margin decrease was partially offset by margins earned from increased system throughput volume production. The increased volumes were from regions exposed to both commodity prices and fixed fees.

System throughput volumes increased by 82 MMcfd, or 31%, from 262 MMcfd in the three months ended June 30, 2008 to 344 MMcfd in the same period of 2009. This increase in throughput volumes was primarily due to the continued successful development by producers operating in the vicinity of the Panhandle System, as well as our success in contracting and connecting new supply. The Crossroads plant in East Texas, which became fully operational in April 2008, and the acquisition of Lone Star Gathering L.P., or Lone Star, which was consummated in the third quarter of 2008, also contributed to the volume increase.

During the three months ended June 30, 2009, we generated a majority of our gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 4 – “Derivative Instruments,” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of our derivatives program. Adjusted for the cash impact of our commodity derivative instruments, our gross margin increased by $0.5 million, or 2%, from $23.8 million in the three months ended June 30, 2008 to $24.3 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of our commodity derivatives, our gross margin decreased by $0.23 Mcf, or 23%, from $1.00 per Mcf in the three months ended June 30, 2008 to $0.77 in the same period of 2009. These changes were primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Producer Services Revenues. Producer services revenues decreased by $1.5 million, or 72%, from $2.1 million to $0.6 million in the three months ended June 30, 2008 compared to the same period of 2009. This decrease was primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas as well as a decrease in fees earned from marketing.

Expenses. Operating expenses increased by $1.9 million, or 39%, from $4.8 million in the three months ended June 30, 2008 to $6.7 million in the same period of 2009. This increase in operating expenses was primarily due to increased costs for compressor rentals, related to our expanding footprint in the Texas and Oklahoma panhandle, expansion projects and recent acquisitions. Taxes other than income remained relatively constant from the three months ended June 30, 2008 to the same period of 2009. General and administrative expenses increased by $0.7 million, or 22%, from $3.5 million in the three months ended June 30, 2008 to $4.2 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs. Depreciation and amortization expenses increased by $4.1 million, or 75%, from $5.4 million in the three months ended June 30, 2008 to $9.5 million in the same period of 2009. The increase in depreciation and amortization expense was primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants and our 2008 acquisitions.

24

Six Months Ended June 30, 2009 Compared With the Six Months Ended June 30, 2008

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 six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,						% Change
	2009			2008
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	148,364		$	215,204		(31	%)
Natural gas liquids		69,523			126,704		(45	%)
Condensate		6,848			14,668		(53	%)
Gathering, processing and transportation fees		5,704			3,269		74	%
Total natural gas midstream revenues (1)		230,439			359,845		(36	%)
Equity earnings in equity investment		1,748			556		214	%
Producer services		595			3,568		(83	%)
Total revenues		232,782			363,969		(36	%)
Expenses
Cost of midstream gas purchased (1)		192,774			302,516		(36	%)
Operating		13,474			8,867		52	%
Taxes other than income		1,478			1,306		13	%
General and administrative		8,481			6,802		25	%
Depreciation and amortization		18,562			10,480		77	%
Total operating expenses		234,769			329,971		(29	%)
Operating income (loss)	$	(1,987	)	$	33,998		(106	%)
Operating Statistics
System throughput volumes (MMcf)		63,622			41,171		55	%
Daily throughput volumes (MMcfd)		352			226		56	%
Gross margin	$	37,665		$	57,329		(34	%)
Cash impact of derivatives		7,169			(16,600	)	143	%
Gross margin, adjusted for impact of derivatives	$	44,834		$	40,729		10	%
Gross margin ($/Mcf)	$	0.59		$	1.39		(58	%)
Cash impact of derivatives ($/Mcf)		0.11			(0.40	)	128	%
Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.70		$	0.99		(29	%)

(1) In the six months ended June 30, 2009, we recorded $41.2 million of natural gas midstream revenue and $41.2 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. These transactions do not impact our gross margin.

Gross Margin. The 34% gross margin decrease in the six months ended June 30, 2009 as compared to the same period of 2008 was a result of decreased commodity pricing and frac spreads, partially offset by margins earned from increased system throughput volume production.

System throughput volumes increased by 126 MMcfd, or 56%, from 226 MMcfd in the six months ended June 30, 2008 to 352 MMcfd in the same period of 2009. This increase in throughput volumes was primarily due to the continued successful development by producers operating in the vicinity of the Panhandle System, as well as our success in contracting and connecting new supply. The Crossroads plant in East Texas, which became fully operational in April 2008, and the acquisition of Lone Star, which was consummated in the third quarter of 2008, also contributed to the volume increase.

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During the six months ended June 30, 2009, we generated a majority of our gross margin from contractual arrangements under which the gross margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See Note 4 – “Derivative Instruments,” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements,” for a description of our derivatives program. Adjusted for the cash impact of our commodity derivative instruments, our gross margin increased by $4.1 million, or 10%, from $40.7 million in the six months ended June 30, 2008 to $44.8 million in the same period of 2009. On a per Mcf basis, adjusted for the cash impact of our commodity derivatives, our gross margin decreased by $0.29 Mcf, or 29%, from $0.99 per Mcf in the six months ended June 30, 2008 to $0.70 in the same period of 2009. These changes were primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Equity Earnings in Equity Investment. Our equity earnings increased $1.1 million, or 214%, from $0.6 million in the six months ended June 30, 2008 to $1.7 million in the same period of 2009. This increase was due to our 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We acquired this member interest in the second quarter of 2008.

Producer Services Revenues. Producer services revenues decreased by $3.0 million, or 83%, from $3.6 million to $0.6 million in the six months ended June 30, 2009 compared to the same period of 2008. This decrease was primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas as well as a decrease in the fees earned from marketing.

Expenses. Operating expenses increased by $4.6 million, or 52%, from $8.9 million in the six months ended June 30, 2008 to $13.5 million in the same period of 2009. This increase in operating expenses was primarily due to increased costs for compressor rentals related to our expanding footprint in areas of operation, including the addition of the Spearman and Crossroads plants. Taxes other than income increased by $0.2 million, or 13%, from $1.3 million in the six months ended June 30, 2008 to $1.5 million in the same period of 2009 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $1.7 million, or 25%, from $6.8 million in the six months ended June 30, 2008 to $8.5 million in the same period of 2009 primarily due to increased staffing and related employee benefit costs. Depreciation and amortization expenses increased by $8.1 million, or 77%, from $10.5 million in the six months ended June 30, 2008 to $18.6 million in the same period of 2009. This increase in depreciation and amortization expense was primarily due to capital spending on expansion projects, such as the Spearman and Crossroads plants and our 2008 acquisitions.

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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 three and six months ended June 30, 2009 and 2008 (in thousands):

	Three Months Ended June 30,						% Change		Six Months Ended June 30,						% Change
	2009			2008					2009			2008
Operating income	$	21,393		$	44,329		(52	%)	$	43,320		$	75,563		(43	%)
Other income (expense)
Interest expense		(6,365	)		(5,374	)	18	%		(11,981	)		(10,306	)	16	%
Other		328			458		(28	%)		646			920		(30	%)
Derivatives		(2,034	)		(29,942	)	(93	%)		(9,195	)		(22,166	)	(59	%)
Net income	$	13,322		$	9,471		41	%	$	22,790		$	44,011		(48	%)

Interest Expense. Our consolidated interest expense increased $1.0 million, or 18%, from $5.4 million in the three months ended June 30, 2008 to $6.4 million in the same period of 2009. Our consolidated interest expense for the three and six months ended June 30, 2009 and 2008 is comprised of the following (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
Source	2009			2008			2009			2008
Borrowings	$	5,596		$	4,935		$	10,464		$	10,622
Capitalized interest		(149	)		(187	)		(226	)		(675	)
Interest rate swaps		918			626			1,743			359
Total interest expense	$	6,365		$	5,374		$	11,981		$	10,306

Interest expense for both the three and six months ended June 30, 2009 increased from the comparative periods in 2008 due to an increase in our weighted average debt balance caused by our past capital spending program including acquisitions and an increase in non-cash interest expense related to debt issuance costs, partially offset by an interest rate decrease.

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. Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. We determine the fair values of our commodity derivative instruments 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, in accordance with Statement of Financial Accounting Standards No. 157,Fair Value Measurements.

Our derivative activity for the three and six months ended June 30, 2009 and 2008 is summarized below (in thousands):

	Three Months Ended June 30,						Six Months Ended June 30,
	2009			2008			2009			2008
Interest Rate Swap unrealized derivative gain	$	3,574		$	—		$	3,416		$	—
Interest Rate Swap realized derivative loss		(1,764	)		—			(2,720	)		—
Natural gas midstream commodity unrealized derivative loss		(7,221	)		(20,239	)		(17,060	)		(2,941	)
Natural gas midstream commodity realized derivative gain (loss)		3,377			(9,703	)		7,169			(19,225	)
Total derivative loss	$	(2,034	)	$	(29,942	)	$	(9,195	)	$	(22,166	)

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Liquidity and Capital Resources

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under our $800.0 million revolving credit facility, or the Revolver, and proceeds from equity offerings. As discussed in more detail in “–Long-Term Debt” below, as of June 30, 2009, we had availability of $201.3 million on the Revolver. We fund our debt service obligations and distributions to unitholders solely using cash generated from our operations. We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital expenditures (other than major capital improvements or acquisitions), scheduled debt payments under the Revolver and our distribution payments for the remainder of 2009. However, our ability to satisfy our obligations and planned expenditures in the future will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control. Depending on the longevity and ultimate severity of the deterioration of the global economy, our ability to meet our working capital requirements and capital expenditures, including our ability to grow organically in the future through acquisitions, may be significantly adversely affected, as may our ability to make debt payments and cash distributions to our limited partners and to PVG, the owner of our general partner.

Cash Flows

The following table summarizes our cash flow statements for the six months ended June 30, 2009 and 2008:

	Six Months Ended June 30,
	2009			2008
	(in thousands)
Cash flows from operating activities:
Net income contribution	$	22,790		$	44,011
Adjustments to reconcile net income to net cash provided operating activities (summarized)		49,167			29,726
Net changes in operating assets and liabilities		1,601			(410	)
Net cash provided by operating activities		73,558			73,327
Net cash used in investing activities		(33,548	)		(134,405	)
Net cash provided by (used in) financing activities		(42,013	)		59,380
Net decrease in cash and cash equivalents	$	(2,003	)	$	(1,698	)

Operating Activities. At June 30, 2009, we had $7.5 million in cash and cash equivalents compared to $9.5 million at December 31, 2008. Cash provided by operating activities for the six months ended June 30, 2009 was approximately $73.6 million compared to $73.3 million for the six months ended June 30, 2008. Cash flows provided by operating activities remained relatively constant from the six months ended June 30, 2008 to the same period of 2009. The effects of decreased commodity prices on our cash flows were partially offset by the effects of cash received in settlement of our commodity derivative instruments.

Investing Activities. Cash used in investing activities was approximately $33.5 million for the six months ended June 30, 2009 compared to $134.4 million for the six months ended June 30, 2008. This decrease was due to lower acquisition activity during the six months ended June 30, 2009, compared to the same period of the prior year, as a result of economic conditions and lower commodity prices.

Financing Activities. Cash used in financing activities was approximately $42.0 million for the six months ended June 30, 2009 compared to cash provided of $59.4 million for the six months ended June 30, 2008. During the six months ended June 30, 2008, an equity issuance provided net proceeds of approximately $141.0 million and was used in part to repay borrowings under the Revolver. The proceeds from borrowings during both periods were used to fund our capital expenditures.

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Long-Term Debt

Revolver. In March 2009, we increased the size of the Revolver from $700.0 million to $800.0 million, which resulted in $9.3 million of debt issuance costs. The Revolver is secured with substantially all of our assets. As of June 30, 2009, we had remaining borrowing capacity of $201.3 million on the Revolver net of outstanding borrowings of $597.1 million and letters of credit of $1.6 million. The Revolver matures in December 2011 and is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10.0 million sublimit for the issuance of letters of credit. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option or at a rate derived from the London Interbank Offered Rate, or LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. At June 30, 2009, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 2.5%. We have entered into interest rate swaps, or Interest Rate Swaps, to establish fixed rates on a portion of the outstanding borrowings under the Revolver. As of June 30, 2009, we were in compliance with all of our covenants under the Revolver.

Future Capital Needs and Commitments

We believe that short-term cash requirements for operating expenses and quarterly distributions to PVG, as the owner of our general partner, and unitholders will be funded through operating cash flows. We also believe that our remaining borrowing capacity will be sufficient for our capital needs and commitments for the remainder of 2009. Subject to commodity prices and the availability of capital, we are committed to the growth of both our business segments through a combination of organic projects and acquisitions of new properties and assets. For the remainder of 2009, we anticipate making capital expenditures of approximately $61.3 to $66.3 million. The majority of the 2009 capital expenditures are expected to be incurred in the natural gas midstream segment, including our July 2009 acquisition of gas processing and residue pipeline facilities in western Oklahoma from Atlas Pipeline Partners, L.P. for approximately $22.6 million in cash, which was funded by borrowings under the Revolver.

Long-term cash requirements for acquisitions and other capital expenditures are expected to be funded by several sources, including cash flows from operating activities, borrowings under the Revolver and the issuance of additional debt and equity securities if available under commercially acceptable terms. However, disruptions in the global financial and commodities markets and the general economic climate have made access to equity and debt capital markets very difficult since late in 2008. While signs of improvement in these markets have occurred, including issuances of debt and equity securities by other publicly traded partnerships, the short-term outlook remains uncertain with respect to our ability to access the capital markets on acceptable terms. If the situation deteriorates and we are unable to access the capital markets for an extended period, our ability to make acquisitions and other capital expenditures, as well as our ability to increase or sustain cash distributions to our limited partners and to PVG, the owner of our general partner, will likely become impaired. If additional financing is required, there are no assurances that it will be available, or if available, that it can be obtained on terms favorable to us or not dilutive to our future earnings.

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 June 30, 2009 and December 31, 2008, our environmental liabilities included $1.1 million and $1.2 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.

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Summary of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. Our most critical accounting policies which involve the judgment of our management were fully disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008 and remained unchanged as of June 30, 2009.

Recent Accounting Pronouncements

See Note 12—“New Accounting Standards” in the Notes to Condensed Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Because such statements include risks, uncertainties and contingencies, actual results may differ materially from those expressed or implied by such forward-looking statements. These risks, uncertainties and contingencies include, but are not limited to, the following:

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

• our ability to access external sources of capital;

• any impairment writedowns of our assets;

• the relationship between natural gas, NGL and coal prices;

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

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

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

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

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

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

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

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

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

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

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

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• 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 fiscal year ended December 31, 2008.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the SEC, including our Annual Report on Form 10-K for the year ended December 31, 2008. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

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Item 3 Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. The principal market risks to which we are exposed are as follows:

• Price Risk

• Interest Rate Risk

• Customer Credit Risk

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

Price Risk

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

At June 30, 2009, we reported a commodity derivative asset related to our natural gas midstream segment of $5.7 million that is with three counterparties and is substantially concentrated with one 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. The maximum amount of loss due to credit risk if counterparties to our derivative asset positions fail to perform according to the terms of the contracts would be equal to the fair value of the contracts as of June 30, 2009. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

For the three months ended June 30, 2009 and 2008, we reported net derivative losses of $2.0 million and $9.2 million. Because we no longer use hedge accounting for our commodity derivatives or Interest Rate Swaps, we recognize changes in fair value in earnings currently in the derivatives line item of our condensed consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. The discontinuation of hedge accounting has no impact on our reported cash flows, although our results of operations are affected by the volatility of mark-to-market 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.

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The following table lists our derivative agreements and their fair values as of June 30, 2009:

		Weighted Average Price Collars
	Average Volume Per Day	Additional Put Option		Put		Call		Fair Value (in thousands)
	(in barrels)			(per barrel)
Crude Oil Three-Way Collar
Third Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	2,634
	(in MMBtu)			(per MMBtu)
Frac Spread Collar
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		1,235
	(in barrels)			(per barrel)
Crude Oil Collar
Second Quarter 2010 through Fourth Quarter 2010	750			$	70.00	$	81.25		28
Settlements to be received in subsequent period									1,781
Natural gas midstream segment commodity derivatives - net asset								$	5,678

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, natural gas midstream gross margin and operating income for the remainder of 2009 would decrease or increase by approximately $2.5 million. In addition, we estimate that for every $5.00 per barrel increase or decrease in the crude oil price, natural gas midstream gross margin and operating income for the second half of 2009 would increase or decrease by approximately $2.4 million. This assumes that natural gas prices, crude oil prices and inlet volumes remain constant at anticipated levels. These estimated changes in gross margin and operating income exclude potential cash receipts or payments in settling these derivative positions.

We estimate that a $5.00 per barrel increase in the crude oil price would decrease the fair value of the crude oil collars by $1.6 million. We estimate that a $5.00 per barrel decrease in the crude oil price would increase the fair value of the crude oil collars by $1.5 million. In addition, we estimate that a $1.00 per MMBtu increase or decrease in the natural gas purchase price and a $4.65 per barrel (the estimated equivalent of $5.00 per barrel of crude oil) increase or decrease in the NGL sales price would affect the fair value of the frac spread collar by $0.1 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of June 30, 2009, we had $597.1 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Interest Rate Swaps to effectively convert the interest rate on $310.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 3.54% plus the applicable margin until March 2010. From March 2010 to December 2011, the notional amounts of the Interest Rate Swaps total $250.0 million 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, with us paying a weighted average fixed rate of 2.09% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. The Interest Rate Swaps extend one year past the maturity of the current Revolver. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) as of June 30, 2009 would cost us approximately $2.9 million in additional interest expense per annum.

In the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. Our results of operations are affected by the volatility of changes in fair value, which fluctuates with changes in interest rates. These fluctuations could be significant. See Note 4 – “Derivative Instruments,” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements,” for a further description of our derivatives program.

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Customer Credit Risk

We are exposed to the credit risk of our natural gas midstream customers and coal lessees. For the six months ended June 30, 2009, two of our natural gas midstream segment customers accounted for $56.3 million and $35.6 million, or 18% and 12%, of our total consolidated revenues. At June 30, 2009, 20% of our consolidated accounts receivable related to these customers. No significant uncertainties related to the collectability of amounts owed to us exist in regard to these two natural gas midstream customers.

This customer concentration increases our exposure to credit risk on our receivables, since 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 June 30, 2009, no receivables were collateralized, and we had a $2.0 million allowance for doubtful accounts recorded for the natural gas midstream and coal and natural resource management segments.

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Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2009. 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 June 30, 2009, such disclosure controls and procedures were effective.

(b) Changes in Internal Control Over Financial Reporting

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

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PART II. OTHER INFORMATION

Item 6 Exhibits

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.

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SIGNATURES

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

			PENN VIRGINIA RESOURCE PARTNERS, L.P.
			By: PENN VIRGINIA RESOURCE GP, LLC
Date:	August 6, 2009	By:	/s/ Frank A. Pici
			Frank A. Pici
			Vice President and Chief Financial Officer
Date:	August 6, 2009	By:	/s/ Forrest W. McNair
			Forrest W. McNair
			Vice President and Controller

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