UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 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	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

As of May 7, 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 Months Ended March 31, 2009 and 2008	1
	Condensed Consolidated Balance Sheets as of March 31, 2009 and December 31, 2008	2
	Condensed Consolidated Statements of Cash Flows for the Three Months Ended March 31, 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
Item 4	Submission of Matters to a Vote of Security Holders	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
	March 31,
	2009			2008
Revenues
Natural gas midstream	$	117,379		$	125,048
Coal royalties		30,630			23,962
Coal services		1,888			1,862
Other		6,862			5,942
Total revenues		156,759			156,814
Expenses
Cost of midstream gas purchased		100,620			99,697
Operating		8,890			6,793
Taxes other than income		1,223			1,072
General and administrative		7,596			6,518
Depreciation, depletion and amortization		16,503			11,500
Total expenses		134,832			125,580
Operating income		21,927			31,234
Other income (expense)
Interest expense		(5,616	)		(4,932	)
Other		318			462
Derivatives		(7,161	)		7,776
Net income	$	9,468		$	34,540
General partner’s interest in net income	$	6,104		$	4,627
Limited partners’ interest in net income	$	3,364		$	29,913
Basic and diluted net income per limited partner unit (see Note 6)	$	0.06		$	0.64
Weighted average number of units outstanding, basic		51,799			46,106
Weighted average number of units outstanding, diluted		51,835			46,106

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)

	March 31,			December 31,
	2009			2008
Assets
Current assets
Cash and cash equivalents	$	12,681		$	9,484
Accounts receivable, net of allowance for doubtful accounts		57,236			73,267
Derivative assets		21,692			30,431
Other current assets		4,451			4,263
Total current assets		96,060			117,445
Property, plant and equipment		1,109,382			1,093,526
Accumulated depreciation, depletion and amortization		(213,163	)		(198,407	)
Net property, plant and equipment		896,219			895,119
Equity investments		80,002			78,442
Intangible assets, net		90,817			92,672
Other long-term assets		43,621			35,141
Total assets	$	1,206,719		$	1,218,819
Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	46,845		$	60,390
Accrued liabilities		6,955			10,796
Deferred income		3,762			4,842
Derivative liabilities		15,719			13,585
Total current liabilities		73,281			89,613
Deferred income		5,671			6,150
Other liabilities		16,900			17,359
Derivative liabilities		6,176			6,915
Long-Term debt		595,100			568,100
Partners’ capital		509,591			530,682
Total liabilities and partners’ capital	$	1,206,719		$	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 March 31,
	2009			2008
Cash flows from operating activities
Net income	$	9,468		$	34,540
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		16,503			11,500
Derivative contracts:
Total derivative losses (gains)		7,615			(6,668	)
Cash received (paid) to settle derivatives		2,836			(9,522	)
Non-cash interest expense		491			164
Equity earnings, net of distributions received		(1,559	)		(360	)
Other		(295	)		(309	)
Changes in operating assets and liabilities		(686	)		(499	)
Net cash provided by operating activities		34,373			28,846
Cash flows from investing activities
Acquisitions		(1,256	)		(20	)
Additions to property, plant and equipment		(17,050	)		(17,650	)
Other		265			341
Net cash used in investing activities		(18,041	)		(17,329	)
Cash flows from financing activities
Distributions to partners		(30,877	)		(24,718	)
Proceeds from borrowings		27,000			25,000
Repayments of borrowings		—			(23,000	)
Payment of debt issuance costs		(9,258	)		—
Net cash used in financing activities		(13,135	)		(22,718	)
Net increase (decrease) in cash and cash equivalents		3,197			(11,201	)
Cash and cash equivalents – beginning of period		9,484			19,530
Cash and cash equivalents – end of period	$	12,681		$	8,329
Supplemental disclosure:
Cash paid for interest	$	6,156		$	6,123

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

March 31, 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 coal and natural resource management segment primarily involves the management and leasing of coal properties and the subsequent collection of royalties. Our coal reserves are primarily located in Kentucky, Virginia, West Virginia, Illinois and New Mexico. We also earn revenues from other land management activities, such as selling standing timber, leasing fee-based coal-related infrastructure facilities to certain lessees and end-user industrial plants, collecting oil and gas royalties and from coal transportation, or wheelage, fees.

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. In addition, we own a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded Delaware limited partnership. At March 31, 2009, Penn Virginia owned an approximately 77% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At March 31, 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. Summary of Significant Accounting Policies

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2008. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our condensed consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. We own a 25% member interest in Thunder Creek, a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin, and a 50% member interest in a coal handling joint venture. Earnings from our 25% member interest in Thunder Creek are recorded in the other revenues line on the condensed consolidated statements of income and earnings from our 50% member interest in a coal handling venture are recorded in the coal services line on the condensed consolidated statements of income. Our investments in these equity affiliates are recorded on the equity investments line on the condensed consolidated balance sheets.

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. These financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2008. Operating results for the three months ended March 31, 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.

4

New Accounting Standards

In April 2009, the Financial Accounting Standards Board (“FASB”) issued FSP FAS 107-1 and APB 28-1, Interim Disclosures About Fair Value of Financial Instruments (“FSP FAS 107-1 and APB 28-1”). This FSP 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 have elected to adopt this FSP for the three months ended March 31, 2009. This FSP does not require disclosures for earlier periods presented for comparative purposes at initial adoption. See Note 3, “Fair Value Measurements” for the disclosure required under FSP FAS 107-1 and APB 28-1.

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 (“FSP FAS 141(R)-1”). This FSP 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, an asset or liability shall be recognized at the acquisition at the amount that would be recognized in accordance with Statement of Financial Accounting Standards (“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. Certain disclosures are also required under this standard. 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 December 15, 2008. We have had no material acquisitions since our adoption of this FSP. 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.

3. Fair Value Measurements

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

Our financial instruments consist of cash and cash equivalents, receivables, accounts payable, derivative instruments and long-term debt. At March 31, 2009, the carrying values of all of these financial instruments approximated fair value.

SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

• Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

• Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

• Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

5

The following table summarizes the valuation of certain assets and liabilities by the above SFAS No. 157 categories as of March 31, 2009 (in thousands):

				Fair Value Measurements at March 31, 2009, Using
Description	Fair Value Measurements at March 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Interest rate swap liability - current		(6,925	)		—		(6,925	)		—
Interest rate swap liability - noncurrent		(6,176	)		—		(6,176	)		—
Commodity derivative assets - current		21,692			—		21,692			—
Commodity derivative liability - current		(8,794	)		—		(8,794	)		—
Total	$	(203	)	$	—	$	(203	)	$	—

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

We use the following methods and assumptions to estimate the fair values of the assets and liabilities outlined in the above table:

• 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”). We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. This is a Level 2 input. See Note 4 – “Derivative Instruments.”

• Commodity derivative instruments: Our natural gas midstream segment’s commodity derivatives utilize three-way collar derivative contracts. We also utilize a combination of collar derivative contracts and commodity swaps to hedge against the variability in the frac spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities, and use discount rates adjusted for the credit risk of the counterparties if the derivative is in an asset position and our own credit risk for derivatives in a liability position. This is a Level 2 input. We use the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 4 – “Derivative Instruments.”

4. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize three-way collar derivative contracts to hedge against the variability in cash flows associated with anticipated natural gas midstream revenues and cost of midstream gas purchased. We also utilize a combination of collar derivative contracts and swap contracts to hedge against the variability in our frac spread. Our frac spread is the spread between the purchase price for the natural gas we purchase from producers and the sale price for natural gas liquids (“NGLs”) that we sell after processing. We hedge against the variability in our frac spread by entering into costless collar and swap derivative contracts to sell NGLs forward at a predetermined commodity price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. While the use of derivative instruments limits the risk of adverse price movements, such use may also limit future revenues or cost savings from favorable price movements.

A three-way collar contract consists of a collar contract plus a put option contract sold by us with a price below the floor price of the collar. The counterparty to a collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. The additional put option sold by us requires us to make a payment to the counterparty if the settlement price for any

6

settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. If market prices are below the additional put option, we would be entitled to receive the market price plus the difference between the additional put option and the floor. See the natural gas midstream segment commodity derivative table in this footnote. This strategy enables us to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

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 March 31, 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 for derivatives in a liability position. The following table sets forth our positions as of March 31, 2009 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

	Average Volume Per Day	Weighted Average Price Collars						Fair Value (in thousands)
		Additional Put Option		Put		Call
Crude Oil Three-way Collar	(in barrels)				(per barrel)
Second Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	4,939
Frac Spread Collar	(in MMBtu)				(per MMBtu)
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		5,594
Settlements to be received in subsequent period									2,366
Natural gas midstream segment commodity derivatives—net asset								$	12,899

At March 31, 2009, we reported a net derivative asset related to the natural gas midstream segment of $12.9 million. See the Financial Statement Impact of Derivatives section below for the impact of the natural gas midstream commodity derivatives on our condensed consolidated statements of income.

Interest Rate Swaps

We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. The following table sets forth our Interest Rate Swap positions at March 31, 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	%

The notional amount of $310.0 million represents approximately 52% of our total long-term debt outstanding at March 31, 2009. The weighted-average fixed rate is paid by us based on the notional amount, with the counterparties paying a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). The Interest Rate Swaps extend one year past the maturity of the Revolver. The Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions.

During the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, subsequent fair value gains and losses for the Interest Rate Swaps are recognized in earnings currently. At March 31, 2009, a $3.9 million loss remained in accumulated other comprehensive income (“AOCI”) related to these discontinued Interest Rate Swap hedges. The $3.9 million loss will be recognized in earnings through the end of 2011 as the originally forecasted transactions occur.

7

We reported a (i) net derivative liability of $13.1 million at March 31, 2009 and (ii) loss in AOCI of $3.9 million at March 31, 2009 related to the Interest Rate Swaps. In connection with periodic settlements, we recognized $0.8 million of net hedging losses on the Interest Rate Swaps in interest expense during the three months ended March 31, 2009.

Financial Statement Impact of Derivatives

In both the three months ended March 31, 2009 and 2008, we reclassified a total of $0.8 million out of AOCI and into earnings. We also recorded unrealized hedging losses of $0.5 million and $5.1 million in AOCI in the three months ended March 31, 2009 and 2008 related to the Interest Rate Swaps. See Note 9, “Comprehensive Income,” for a detailed schedule of our AOCI.

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 months ended March 31, 2009 and 2008 (in thousands):

	Location of gain (loss) on derivatives recognized in income	Three Months Ended March 31, 2009			Three Months Ended March 31, 2008
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts (1)	Interest expense	$	(825	)	$	267
Increase (decrease) in net income resulting from derivatives de-designated as hedging instruments under SFAS No. 133		$	(825	)	$	267
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivatives	$	(1,114	)	$	—
Commodity contracts (1)	Natural gas midstream revenues		—			(2,251	)
Commodity contracts (1)	Cost of midstream gas purchased		—			1,143
Commodity contracts	Derivatives		(6,047	)		7,776
Increase (decrease) in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	(7,161	)	$	6,668
Total increase (decrease) in net income resulting from derivatives		$	(7,986	)	$	6,935
Realized and unrealized derivative impact:
Cash received for commodity and interest rate contract settlements	Derivatives		2,836			(9,522	)
Cash paid for interest rate contract settlements	Interest expense		(370	)		267
Non-settlement derivative gains	(2)		(10,452	)		16,190
Total increase (decrease) in net income resulting from derivatives		$	(7,986	)	$	6,935

(1) This represents amounts reclassified out of AOCI and into earnings. At March 31, 2009, a $3.9 million loss remained in AOCI related to Interest Rate Swaps on which we discontinued hedge accounting.

(2) This activity represents unrealized gains in the natural gas midstream, cost of midstream gas purchased, interest expense and derivatives lines on our condensed consolidated statements of income.

8

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 March 31, 2009 and December 31, 2008 (in thousands):

	Balance Sheet Location	Fair values as of March 31, 2009				Fair values as of December 31, 2008
		Derivative Assets		Derivative Liabilities		Derivative Assets		Derivative Liabilities
Derivatives de-designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	—	$	—	$	1,228
Interest rate contracts	Derivative liabilities - noncurrent		—		—		—		1,842
Total derivatives de-designated as hedging instruments under SFAS No. 133		$	—	$	—	$	—	$	3,070
Derivatives not designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	6,925	$	—	$	4,663
Interest rate contracts	Derivative liabilities - noncurrent		—		6,176		—		5,073
Commodity contracts	Derivative assets/liabilities - current		21,692		8,794		30,431		7,694
Total derivatives not designated as hedging instruments under SFAS No. 133		$	21,692	$	21,895	$	30,431	$	17,430
Total fair values of derivative instruments		$	21,692	$	21,895	$	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 the effect of the Interest Rate Swaps on our total interest expense for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
Source	2009			2008
	(in thousands)
Borrowings	$	(4,868	)	$	(5,687	)
Capitalized interest		77			488
Interest rate swaps		(825	)		267
Total interest expense	$	(5,616	)	$	(4,932	)

During the three months ended March 31, 2009 and 2008 we applied hedge accounting to some of our interest rate hedges. Settlements on the Interest Rate Swaps that follow hedge accounting are recorded as reclassification amounts out of AOCI to interest expense. For the three months ended March 31, 2009 we reclassified $0.8 million in interest rate swap cash payments to interest expense, and $0.3 million in interest rate swap cash receipts for the same period in 2008.

The effects of derivative gains (losses), cash settlements of our natural gas midstream commodity derivatives and cash settlements of the Interest Rate Swaps are reported as adjustments to reconcile net income to net cash provided by operating activities on our condensed consolidated statements of cash flows. These items are recorded in the “Total derivative losses (gains)” and “Cash settlements of derivatives” lines on the condensed consolidated statements of cash flows.

At March 31, 2009, we reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 million that is with two counterparties, which are 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 March 31, 2009 and March 31, 2008. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

The above hedging activity represents cash flow hedges. As of March 31, 2009, we did not own derivative instruments that were classified as fair value hedges or trading securities. In addition, as of March 31, 2009, we did not own derivative instruments containing credit risk contingencies.

9

5. Long-Term Debt

In March 2009, we increased the size of our 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 LIBOR, plus an applicable margin ranging from 1.75% to 2.75% if we select the LIBOR-based borrowing option. As of March 31, 2009 and March 31, 2008 our interest rate on the Revolver was 3.75% and 4.15%, respectively.

6. Partners’ Capital and Distributions

As of March 31, 2009, partners’ capital consisted of 51.8 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of March 31, 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

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 retrospectively to all periods presented.

The Partnership’s securities consist of publicly traded common units held by limited partners, a general partner interest and separately transferable incentive distribution rights (“IDR”). EITF 07-04 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 07-04 requires net income or loss for a reporting period to be reduced (or increased) by the amount of Available Cash (as defined by the 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 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%, respectively, 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 three months ended March 31, 2009, our general partner granted 354,792 phantom units. See Note 8, “Unit-Based Compensation” for a description of phantom units. These share-based payment awards contain rights to receive nonforfeitable dividends 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 partnership 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.

10

The following table reconciles net earning to earnings allocable to limited partners (in thousands):

	Three Months Ended March 31,
	2009			2008
Net income	$	9,468		$	34,540
Less:
Distributions payable on behalf of incentive distribution rights		(6,035	)		(4,469	)
Distributions payable on behalf of general partner interest		(497	)		(423	)
General partner interest in excess of distributions over earnings (excess of earnings over distributions) allocable to the general partner interest		428			(178	)
Net income allocable to limited partners	$	3,364		$	29,470
The following table reconciles the computation of basic and diluted weighted average units (in thousands):
	Three Months Ended March 31,
	2009			2008
Basic weighted average limited partner units		51,799			46,106
Dilutive effect of restricted phantom units		36			—
Diluted weighted average limited partner units		51,835			46,106
Net income per limited partner, basic	$	0.06		$	0.64
Net income per limited partner, diluted	$	0.06		$	0.64

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 or (iii) provide funds for distributions to unitholders and our general partner for any one or more of the next four quarters.

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

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

11

The following table reflects the allocation of total cash distributions paid by us during the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
	(in thousands, except per unit data)
Limited partner units	$	24,345	$	20,287
General partner interest (2%)		497		414
Incentive distribution rights		6,035		4,017
Total cash distributions paid	$	30,877	$	24,718
Total cash distributions paid per limited partner unit	$	0.47	$	0.44

On May 15, 2009, we will pay a $0.47 per unit quarterly distribution to unitholders of record on May 4, 2009. This distribution was unchanged from the previous distribution paid on February 2, 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 $1.5 million for both the three months ended March 31, 2009 and 2008. These costs are reflected in general and administrative expenses in 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 $4.7 million and $8.0 million as of March 31, 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”), 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 accounts payable 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. Pursuant to the 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 $0.7 million for the three months ended March 31, 2009 and 2008. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

Gathering and Processing Revenues

PVR East Texas and PVOG LP are parties to a natural Gas Gathering and Processing Agreement. Pursuant to the Gas Gathering and Processing Agreement, PVOG LP and PVR East Texas have agreed that PVR East Texas will gather and process all of PVOG

12

LP’s current and future gas production in certain areas of the Bethany Field in East Texas and redeliver the NGLs to PVOG LP for a $0.30/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. In the three months ended March 31, 2009, PVOG LP paid PVR East Texas $0.7 million in fees pursuant to the Gas Gathering and Processing Agreement. 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, Connect Energy transports them to the marketing location, and then Connect Energy resells such gas or NGLs to third parties. The sales price received by PVOG LP from Connect Energy for such gas or NGLs equals the sales price received by Connect Energy for such gas or NGLs from the third parties. In the three months ended March 31, 2009, PVOG LP received $0.4 million from Connect Energy in connection with such sales. In the three months ended March 31, 2009, we recorded $21.2 million of natural gas midstream revenue and $21.2 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG LP and the subsequent sale of that gas to third parties. We take title to the gas and NGLs prior to transporting it to third parties. These transactions do not impact the gross margin, nor do they impact operating income other than the processing and marketing fee noted above.

8. Unit-Based Compensation

We recognized a total of $1.4 million and $0.7 million for the three months ended March 31, 2009 and 2008 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan. During the three months ended March 31, 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. During the same period, 98,322 restricted units with a weighted average grant date fair value of $27.44 per unit vested. 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 on the general and administrative expense line on our condensed consolidated statements of income.

The Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan, or our LTIP, permits the grant of phantom units to employees and directors. No grants of phantom units were made under our LTIP in 2008. 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. If a director’s membership on the board of directors of our general partner terminates for any reason, or an employee’s employment with our general partner and its affiliates terminates for any reason other than retirement after reaching age 62 and completing 10 years of consecutive service, the grantee’s unvested phantom units will be automatically forfeited unless, and to the extent, our Committee provides otherwise. Common units delivered upon the vesting of phantom units may be newly issued units, common units acquired by our general partner in the open market, common units already owned by our general partner, common units acquired by our general partner directly from us or any other person or any combination of the foregoing.

9. Comprehensive Income

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. The following table sets forth the components of comprehensive income for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Net income	$	9,468		$	34,540
Unrealized losses on derivative activities		(506	)		(5,143	)
Reclassification adjustment for derivative activities		825			841
Comprehensive income	$	9,787		$	30,238

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.

13

Environmental Compliance

Our operations and those of our 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 material impact on our financial condition or results of operations.

As of March 31, 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.

11. Segment Information

Segment information has been prepared in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal and natural resource management operations and our natural gas midstream operations. Accordingly, 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.

14

The following table presents a summary of certain financial information relating to our segments as of and for the three months ended March 31, 2009 and 2008 (in thousands):

	Revenues				Operating income (loss)
	Three Months Ended March 31,				Three Months Ended March 31,
	2009		2008		2009			2008
Coal and natural resource	$	38,252	$	30,294	$	24,974		$	17,582
Natural gas midstream		118,507		126,520		(3,047	)		13,652
Consolidated totals	$	156,759	$	156,814	$	21,927		$	31,234
Interest expense					$	(5,616	)	$	(4,932	)
Other						318			462
Derivatives						(7,161	)		7,776
Consolidated net income					$	9,468		$	34,540
	Additions to property and equipment				DD&A expense
	Three Months Ended March 31,				Three Months Ended March 31,
	2009		2008		2009			2008
Coal and natural resource	$	1,300	$	48	$	7,394		$	6,413
Natural gas midstream		17,006		17,622		9,109			5,087
Consolidated totals	$	18,306	$	17,670	$	16,503		$	11,500
	Total assets at
	March 31, 2009		December 31, 2008
Coal and natural resource	$	609,372	$	600,418
Natural gas midstream		597,347		618,401
Consolidated totals	$	1,206,719	$	1,218,819

15

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 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. Both in our current limited partnership form and in our previous corporate form, we have managed coal properties since 1882. We currently conduct operations in two business segments: (i) coal and natural resource management and (ii) natural gas midstream. Our operating income (loss) was $21.9 million in the three months ended March 31, 2009, compared to $31.2 million in the three months ended March 31, 2008. In the three months ended March 31, 2009, our coal and natural resource management segment contributed $25.0 million, or 114%, to operating income. This contribution to operating income was partially offset by a $3.0 million operating loss from our natural gas midstream segment, or 14%.

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 Three Months Ended March 31, 2009:
Revenues	$	38,252	$	118,507		$	156,759
Cost of midstream gas purchased		—		100,620			100,620
Operating costs and expenses		5,884		11,825			17,709
Depreciation, depletion and amortization		7,394		9,109			16,503
Operating income (loss)	$	24,974	$	(3,047	)	$	21,927
For the Three Months Ended March 31, 2008:
Revenues	$	30,294	$	126,520		$	156,814
Cost of midstream gas purchased		—		99,697			99,697
Operating costs and expenses		6,299		8,084			14,383
Depreciation, depletion and amortization		6,413		5,087			11,500
Operating income	$	17,582	$	13,652		$	31,234

The deterioration in global financial markets which began during the third quarter of 2008 and the consequential adverse effect on credit availability continues to adversely impact our access to new capital and credit availability. Depending on the longevity and ultimate severity of this deterioration, our ability to conduct a growth oriented capital spending program will be adversely affected, as could 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.

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 three months ended March 31, 2009, our lessees produced 8.7 million tons of coal from our properties and paid us coal royalties revenues of $30.6 million, for an average royalty per ton of $3.50. Approximately 82% of our coal royalties revenues in the

16

three months ended March 31, 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.

Coal royalties are impacted by several factors that we generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. New legislation or regulations have been or may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and which may require us, our lessees or our lessees’ customers to change operations significantly or incur substantial costs.

To a lesser extent, coal prices also impact coal royalties revenues. Generally, as coal prices change, our average royalty per ton also changes because the majority of our lessees pay royalties based on the gross sales prices of the coal mined. Most of our coal is sold by our lessees under contracts with a duration of one year or more; therefore, changes to our average royalty occur as our lessees’ contracts are renegotiated.

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. Limited access to capital has and could continue to hamper our ability to fund acquisitions, potentially restricting future growth potential. Depending on the longevity and ultimate severity of the deterioration, demand for coal may continue to decline, which could adversely effect 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 PVG, the owner of our general partner.

Natural Gas Midstream Segment

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. As of March 31, 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.

In the three months ended March 31, 2009, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 32.3 Bcf, or approximately 359 MMcfd. In the three months ended March 31, 2009, 25% and 14% of our natural gas midstream segment revenues and 19% and 10% of our total consolidated revenues were derived from two of our natural gas midstream segment customers, Conoco, Inc. and Louis Dreyfus Energy Services.

We continually seek new supplies of natural gas to both offset the natural declines in production from the wells currently connected to our systems and to increase 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 three months ended March 31, 2009, our natural gas midstream segment made aggregate capital expenditures of $14.5 million, primarily related to our Panhandle System where producers continue to develop.

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. Historically, changes in the prices of most NGL products have

17

generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market demand. The deterioration in the global economy, including financial and credit markets, has resulted in a decrease in worldwide demand for oil and domestic demand for natural gas and NGLs. Limited access to capital could continue to hamper our ability to fund acquisitions, potentially restricting future growth potential. Depending on the longevity and ultimate severity of the deterioration, NGL production from our processing plants could decrease and adversely effect our natural gas midstream processing income and our ability to make cash distributions.

Liquidity and Capital Resources

Liquidity and Working Capital

Liquidity is defined as the ability to convert assets into cash or to obtain cash. Short-term liquidity refers to the ability to meet short-term obligations of 12 months or less. Liquidity is a matter of degree and is expressed in terms of working capital and the current ratio and, due to the recent deterioration of the credit and financial markets, in terms of the availability of borrowing capacity against existing credit facilities and debt instruments. Our consolidated working capital (current assets minus current liabilities) and consolidated current ratio (current assets divided by current liabilities) are as follows as of March 31, 2009 and December 31, 2008:

	March 31, 2009		December 31, 2008
Current Assets	$	96,060	$	117,445
Current Liabilities		73,281		89,613
Working Capital	$	22,779	$	27,832
Current Ratio		1.31		1.31

As discussed in more detail in “–Long-Term Debt” below, as of March 31, 2009, we had availability of $203.3 million on the recently expanded $800.0 million revolving credit facility, or the Revolver.

On an ongoing basis, we generally satisfy our working capital requirements and fund our capital expenditures using cash generated from our operations, borrowings under the Revolver and proceeds from equity offerings. 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 and anticipated capital expenditures (other than major capital improvements or acquisitions). We believe that the cash generated from our operations will be sufficient to meet our scheduled debt payments under the Revolver and distribution payments. See Note 6 – “Partners’ Capital and Distributions,” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements,” for a tabular presentation of distribution thresholds.

Our ability to satisfy our obligations and planned expenditures will depend upon our future operating performance, which will be affected by prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control. During the first quarter of 2009, we completed an amendment to increase the borrowing base under our Revolver, with resultant borrowing availability of $203.3 million as of March 31, 2009. However, depending on the longevity and ultimate severity of the recent deterioration of the global economy, including financial and credit markets, our ability in the future to grow organically or through acquisitions may be significantly adversely affected, as may our ability to make cash distributions to our limited partners and to PVG, the owner of our general partner.

18

Cash Flows

The following table summarizes our cash flow statements for the three months ended March 31, 2009 and 2008:

For the Three Months Ended March 31, 2009	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
	(in thousands)
Cash flows from operating activities:
Net income contribution	$	18,537		$	(9,069	)	$	9,468
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		7,690			17,901			25,591
Net change in operating assets and liabilities		(3,896	)		3,210			(686	)
Net cash provided by operating activities	$	22,331		$	12,042			34,373
Net cash used in investing activities	$	(1,035	)	$	(17,006	)		(18,041	)
Net cash used in financing activities								(13,135	)
Net increase in cash and cash equivalents							$	3,197
For the Three Months Ended March 31, 2008	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
	(in thousands)
Cash flows from operating activities:
Net income contribution	$	12,521		$	22,019		$	34,540
Adjustments to reconcile net income to net cash provided by (used in) operating activities (summarized)		5,891			(11,086	)		(5,195	)
Net change in operating assets and liabilities		(4,418	)		3,919			(499	)
Net cash provided by operating activities	$	13,994		$	14,852			28,846
Net cash provided by (used in) investing activities	$	293		$	(17,622	)		(17,329	)
Net cash used in financing activities								(22,718	)
Net decrease in cash and cash equivalents							$	(11,201	)

Net Cash Provided by Operating Activities

Changes to our working capital and to our current ratio are largely affected by net cash provided by operating activities. Net cash provided by operating activities primarily came from the following sources:

Coal and natural resource management segment:

• the collection of coal royalties;

• the sale of standing timber;

• the collection of coal transportation, or wheelage, fees;

• distributions received from our equity investees; and

• settlements from our interest rate swaps, or the Interest Rate Swaps.

Natural gas midstream segment:

• the collection of revenues from natural gas processing contracts with natural gas producers;

• the collection of revenues from our natural gas marketing business; and

• settlements from our natural gas midstream commodity derivatives.

We use the cash provided by operating activities in the coal and natural resource management segment and the natural gas midstream segment in the following ways:

• operating expenses, such as core-hole drilling costs and repairs and maintenance costs;

• taxes other than income, such as severance and property taxes;

• general and administrative expenses, such as office rentals, staffing costs and legal fees;

19

• interest on debt service obligations;

• capital expenditures;

• repayments of borrowings; and

• distributions to our partners.

Net cash provided by operating activities in the three months ended March 31, 2009 increased by $5.6 million, or 19%, to $34.4 million from $28.8 million in the same period of 2008. The overall increase in net cash provided by operating activities was primarily attributable to increased coal royalties received, which was driven primarily by increased production and sales prices of coal in all regions and an increase in cash received from the settlement of our derivative positions. These increases were partially offset by decreased cash received from the sales of residue gas and NGLs, which was primarily driven by a decrease in commodity prices for natural gas and NGLs. See “Results of Operations–Coal and Natural Resource Management Segment” and “Results of Operations–Natural Gas Midstream Segment” for a more detailed explanation of the factors that increased cash provided by our operating activities.

Net Cash Used in Investing Activities

Net cash used in investing activities in the three months ended March 31, 2009 increased by $0.7 million, or 4%, to $18.0 million from $17.3 million in the same period of 2008. The cash used in investing activities for the three months ended March 31, 2009 and 2008 were used primarily for capital expenditures. The following table sets forth capital expenditures by segment made during the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
	(in thousands)
Coal and natural resource management
Acquisitions	$	1,256	$	20
Other property and equipment expenditures		44		28
Total		1,300		48
Natural gas midstream
Expansion capital expenditures		11,200		16,373
Other property and equipment expenditures		3,282		3,106
Total		14,482		19,479
Total capital expenditures	$	15,782	$	19,527

In the three months ended March 31, 2009, PVR made aggregate capital expenditures of $15.8 million. These capital expenditures consisted primarily of expansion capital expenditures in the natural gas midstream segment, primarily to develop additional processing capacity in its Panhandle System. Our natural gas midstream segment also incurred approximately $3.3 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

In the three months ended March 31, 2008, we made aggregate capital expenditures of $19.5 million. These capital expenditures consisted primarily of natural gas midstream segment gathering system expansion projects. Our natural gas midstream segment also incurred $3.1 million of maintenance capital expenditures for equipment overhauls and connecting wells in existing areas.

We funded our coal and natural resource management and natural gas midstream capital expenditures in the three months ended March 31, 2009 and 2008 primarily with cash provided by operating activities and borrowings under the Revolver. See “– Future Capital Needs and Commitments” for an analysis of future capital expenditures and the sources for funding those expenditures.

20

Net Cash Used In Financing Activities

Net cash used in financing activities in the three months ended March 31, 2009 decreased by $9.6 million, or 42%, to $13.1 million from $22.7 million in the same period of 2008. Over the comparative periods, we had an increase in cash distributions to partners, which was related to an increase in the distribution per unit and to $9.3 million debt issuance costs paid in the three months ended March 31, 2009. The increase in cash distributions to partners was due to the increase in the cash distribution paid per unit and to the increase in our outstanding common units resulting from our 2008 unit offering where we issued an additional 5.15 million common units to the public. These increases in cash used in financing activities were partially offset by an increase in net proceeds from our long-term borrowings under the Revolver. See “— Long-Term Debt” below for a more detailed description of our March 31, 2009 long-term debt balance. Net cash provided by financing activities in the three months ended March 31, 2009 and 2008 was used primarily for capital expenditures.

The cash distribution per unit that will be paid to our partners in May 2009 for the first quarter of 2009 will be unchanged from the distribution paid in February 2009. We will continue to be cautious about increasing and maintaining cash distributions to unitholders in the foreseeable future in order to preserve cash liquidity in light of uncertain commodity and financial markets.

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 March 31, 2009, net of outstanding borrowings of $595.1 million and letters of credit of $1.6 million, we had remaining borrowing capacity of $203.3 million on the Revolver. 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. In the three months ended March 31, 2009, we incurred commitment fees of $0.1 million on the unused portion of the Revolver. The interest rate under the Revolver fluctuates based on the ratio of our total indebtedness-to-EBITDA. Interest is payable at a base rate plus an applicable margin of up to 1.25% if we select the base rate borrowing option under the Revolver 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 March 31, 2009, the weighted average interest rate on borrowings outstanding under the Revolver was approximately 3.75%. We do not have a public credit rating for the Revolver.

The financial covenants under the Revolver require us not to exceed specified ratios. We are required to maintain a debt-to-consolidated EBITDA ratio of less than 5.25-to-1.0 and at March 31, 2009, the ratio was 3.37-to-1.0. We are also required to maintain a consolidated EBITDA-to-interest expense ratio of greater than 2.5-to-1.0 and at March 31, 2009, the ratio was 6.31-to-1.0. EBITDA, which is a non-GAAP measure, is generally defined in the Revolver as our net income before the effects of interest expense, interest income, depreciation, depletion and amortization, or DD&A, expense, impairments and other similar charges and non-cash hedging activity. In addition, the Revolver contains various covenants that limit our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business or enter into a merger or sale of our assets, including the sale or transfer of interests in our subsidiaries. As of March 31, 2009, we were in compliance with all of our covenants under the Revolver.

In the event that we would be in default of our covenants, we could appeal to the banks for a waiver of the covenant default. Should the banks deny our appeal to waive the covenant default, the outstanding borrowings under the Revolver would become payable upon demand and would be reclassified to the current liabilities section of our condensed consolidated balance sheet. The Revolver contains cross-default provisions for default of indebtedness of more than $7.5 million. The Revolver does not contain a subjective acceleration clause. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions.

Interest Rate Swaps. We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Interest Rate Swaps total $310.0 million, or approximately 52% of our total long-term debt outstanding as of March 31, 2009, with us paying a weighted average fixed rate of 3.54% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. From March 2010 to

21

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. The Interest Rate Swaps have been entered into with seven financial institution counterparties, with no counterparty having more than 24% of the open positions. After considering the applicable margin of 2.00% in effect as of March 31, 2009, the total interest rate on the $310.0 million portion of Revolver borrowings covered by the Interest Rate Swaps was 5.54% at March 31, 2009. We monitor changes in our counterparties and are not aware of any specific concerns regarding our counterparties’ ability to make payments under any of the Interest Rate Swaps.

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 of $203.3 million will be sufficient for our capital needs and commitments for the remainder of 2009. For the remainder of 2009, we anticipate making capital expenditures, excluding acquisitions, of approximately $47.0 to $53.0 million. The majority of the 2009 capital expenditures are expected to be incurred in the natural gas midstream segment. 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 issuances of additional debt and equity securities if available under commercially acceptable terms.

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

The recent 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 started to arise in 2009, with 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 worsens 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 limited. 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.

22

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the three months ended March 31, 2009 and 2008:

	Three Months Ended March 31,
	2009		2008
	(in thousands, except per unit data)
Revenues	$	156,759	$	156,814
Expenses	$	134,832	$	125,580
Operating income	$	21,927	$	31,234
Net income	$	9,468	$	34,540
Net income per limited partner unit, basic and diluted	$	0.06	$	0.64
Cash flows provided by operating activities	$	34,373	$	28,846

Operating income decreased by $9.3 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to an $8.6 million decrease in gross margin and a $5.0 million increase in DD&A expense, partially offset by a $6.7 million increase in coal royalties revenues.

Net income decreased by $25.1 million in the three months ended March 31, 2009 compared to the same period of 2008 primarily due to the decrease in operating income and a $14.9 million decrease in derivatives.

Coal and Natural Resource Management Segment

Three Months Ended March 31, 2009 Compared With the Three Months Ended March 31, 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 March 31, 2009 and 2008:

	Three Months Ended March 31,						Change
	2009			2008
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	30,630		$	23,962		28	%
Coal services		1,888			1,862		1	%
Timber		1,317			1,584		(17	)%
Oil and gas royalty		703			1,234		(43	)%
Other		3,714			1,652		125	%
Total revenues		38,252			30,294		26	%
Expenses
Coal royalties		1,224			2,512		(51	)%
Other operating		883			231		282	%
Taxes other than income		425			371		15	%
General and administrative		3,352			3,185		5	%
Depreciation, depletion and amortization		7,394			6,413		15	%
Total expenses		13,278			12,712		4	%
Operating income	$	24,974		$	17,582		42	%
Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,748			7,640		15	%
Average royalties revenues per ton ($/ton)	$	3.50		$	3.14		12	%
Less royalties expense per ton ($/ton)		(0.14	)		(0.33	)	(58	)%
Average net coal royalties per ton ($/ton)	$	3.36		$	2.81		20	%

23

Revenues. Coal royalties revenues increased by $6.6 million, or 28%, from $24.0 million in the three months ended March 31, 2008 to $30.6 million in the same period of 2009, primarily due to the increase in the average sales price of coal received by lessees and the overall increase in production from certain subleased properties. Coal royalties expense decreased by $1.3 million, or 51%, from $2.5 million in the three months ended March 31, 2008 to $1.2 million in the same period of 2009, primarily due to decreased production from certain subleased properties in the Central Appalachian region. The average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.55 per ton, or 20%, from $2.81 per ton in the three months ended March 31, 2008 to $3.36 per ton in the same period of 2009. The increase in average net coal royalty per ton was due primarily to the higher royalty revenues per ton received from our lessees in all regions.

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended March 31, 2009 and 2008:

	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended March 31,		Three Months Ended March 31,						Three Months Ended March 31,
Region	2009	2008	2009			2008			2009			2008
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	4,658	4,811	$	21,683		$	18,579		$	4.66		$	3.86
Northern Appalachia	1,057	674		1,951			1,134			1.85			1.68
Illinois Basin	1,261	1,033		3,241			1,938			2.57			1.88
San Juan Basin	1,772	1,122		3,755			2,311			2.12			2.06
Total	8,748	7,640	$	30,630		$	23,962		$	3.50		$	3.14
Less coal royalties expense (1)				(1,224	)		(2,512	)		(0.14	)		(0.33	)
Net coal royalties revenues			$	29,406		$	21,450		$	3.36		$	2.81

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

Coal production in the Central Appalachian region remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Coal production in the Northern Appalachian region increased by 0.4 million tons, or 57%, from 0.7 million tons in the three months ended March 31, 2008 to 1.1 million tons in the same period of 2009. This increase was due primarily to increased production on our longwall mining operations in the region. Coal production in the Illinois Basin region increased by 0.3 million tons, or 22%, from 1.0 million tons in the three months ended March 31, 2008 to 1.3 million tons in the same period of 2009. This increase was due primarily to more efficient mining conditions by certain lessees in Western Kentucky. Coal production in the San Juan Basin region increased by 0.7 million tons, or 58%, from 1.1 million tons in the three months ended March 31, 2008 to 1.8 million tons in the same period of 2009. This increase was due primarily to new mining contracts obtained by lessees in the region.

Coal services revenues remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. Timber revenues decreased by $0.3 million, or 17%, from $1.6 million in the three months ended March 31, 2008 to $1.3 million in the same period of 2009 primarily due to decreased harvesting of timber resulting from weakened market conditions. Oil and gas royalty revenues decreased by $0.5 million, or 43%, from $1.2 million in the three months ended March 31, 2008 to $0.7 million in the same period of 2009, primarily due to decreased natural gas prices. Other revenues increased by $2.0 million, or 125%, from $1.7 million in the three months ended March 31, 2008 to $3.7 million in the same period of 2009, primarily due to forfeited minimum rentals that we recorded as revenue in the three months ended March 31, 2009.

Expenses. Other operating expenses increased by $0.7 million, or 282%, from $0.2 million in the three months ended March 31, 2008 to $0.9 million in the same period of 2009, primarily due to increased core drilling expenses related to coal reserves acquired in May 2008, and increased coal exploration expenses, which were due to coal reserve study expenses incurred in the three months ended March 31, 2009. Both taxes other than income and general and administrative expenses remained relatively constant from the three months ended March 31, 2008 to the same period of 2009. DD&A expenses increased by $1.0 million, or 15%, from $6.4 million in the three months ended March 31, 2008 to $7.4 million in the same period of 2009, primarily due to higher depletion expenses resulting from increased overall coal production.

24

Natural Gas Midstream Segment

Three Months Ended March 31, 2009 Compared With the Three Months Ended March 31, 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 March 31, 2009 and 2008:

	Three Months Ended March 31,						% Change
	2009			2008
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	81,194		$	61,667		32	%
Natural gas liquids		30,606			56,197		(46	)%
Condensate		2,903			6,216		(53	)%
Gathering, processing and transportation fees		2,676			968		176	%
Total natural gas midstream revenues (1)		117,379			125,048		(6	)%
Equity earnings in equity investment		1,119			—		—
Producer services		9			1,472		(99	)%
Total revenues		118,507			126,520		(6	)%
Expenses
Cost of midstream gas purchased (1)		100,620			99,697		1	%
Operating		6,783			4,050		67	%
Taxes other than income		798			701		14	%
General and administrative		4,244			3,333		27	%
Depreciation and amortization		9,109			5,087		79	%
Total operating expenses		121,554			112,868		8	%
Operating income	$	(3,047	)	$	13,652		(122	)%
Operating Statistics
System throughput volumes (MMcf)		32,280			17,287		87	%
System throughput volumes (MMcfd)		359			190		89	%
Gross margin	$	16,759		$	25,351		(34	)%
Impact of derivatives		3,792			(8,414	)	(145	)%
Gross margin, adjusted for impact of derivatives	$	20,551		$	16,937		21	%
Gross margin ($/Mcf)	$	0.52		$	1.47		(65	)%
Impact of derivatives ($/Mcf)		0.12			(0.49	)	(124	)%
Gross margin, adjusted for impact of derivatives	$	0.64		$	0.98		(35	)%

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

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

25

Natural gas midstream revenues decreased by $7.6 million, or 6%, from $125.0 million in the three months ended March 31, 2008 to $117.4 million in the same period of 2009. Cost of midstream gas purchased increased by $0.9 million, or 1%, from $99.7 million in the three months ended March 31, 2008 to $100.6 million in the same period of 2009. The gross margin decreased by $8.6 million, or 34%, from $25.4 million in the three months ended March 31, 2008 to $16.8 million in the same period of 2009. The gross margin decrease was a result of decreased commodity pricing, partially offset by margins earned from increased system throughput volume production. The increased volume was from areas exposed to both commodity prices and fixed fees. There were lower frac spreads during the three months ended March 31, 2009 compared to the same period of 2008. Frac spreads are the difference between the price of NGLs sold and the cost of natural gas purchased on a per MMBtu basis.

System throughput volumes increased by 169 MMcfd, or 89%, from 190 MMcfd in the three months ended March 31, 2008 to 359 MMcfd in the same period of 2009. This increase in throughput volumes is due primarily 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 March 31, 2009, we generated a majority of the 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 impact of our commodity derivative instruments, our gross margin increased by $3.7 million, or 21%, from $16.9 million in the three months ended March 31, 2008 to $20.6 in the same period of 2009. On a per Mcf basis, the gross margin, adjusted for the impact of our commodity derivatives decreased by $0.34 Mcf, or 35%, from $0.98 per Mcf in the three months ended March 31, 2008 to $0.64 in the same period of 2009. These changes are primarily due to the contribution of fixed fee volumes at the Crossroads plant and from the Lone Star acquisition.

Equity Earnings in Equity Investment. This increase is 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 April 2008.

Producer Services Revenues. Producer services revenues decreased by $1.5 million, or 99%, from $1.5 million in the three months ended March 31, 2008 to less than $0.1 million in the same period of 2009 primarily due to the relative changes in natural gas indices from the purchasing and selling of natural gas.

Expenses. Total operating costs and expenses increased primarily due to increased operating expenses, taxes other than income, general and administrative expenses and depreciation and amortization.

Operating expenses increased by $2.7 million, or 67%, from $4.1 million in the three months ended March 31, 2008 to $6.8 million in the same period of 2009. The increase in operating expenses was due primarily to increased costs for chemicals and lubricants, repairs and maintenance expenses and increased compressor rentals, all of which were driven by 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 March 31, 2008 to the same period of 2009. General and administrative expenses increased by $0.9 million, or 27%, from $3.3 million in the three months ended March 31, 2008 to $4.2 million in the same period of 2009, primarily due to increased staffing costs. Depreciation and amortization expenses increased by $4.0 million, or 79%, from $5.1 million in the three months ended March 31, 2008 to $9.1 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.

26

Other

Our other results consist of interest expense and derivative gains and losses.

Interest Expense. Our consolidated interest expense increased by $0.7 million, or 14%, from $4.9 million in the three months ended March 31, 2008 to $5.6 million in the same period of 2009. Our consolidated interest expense for the three months ended March 31, 2009 and 2008 is comprised of the following:

	Three Months Ended March 31,
Source	2009			2008
	(in thousands)
Borrowings	$	(4,868	)	$	(5,687	)
Capitalized interest		77			488
Interest rate swaps		(825	)		267
Total interest expense	$	(5,616	)	$	(4,932	)

The increase in interest expense is primarily due to the effects of the cash payments associated with our Interest Rate Swaps utilized for hedging purposes. These cash payments were partially offset by the decrease in our effective interest rate excluding the effects of the Interest Rate Swaps, which decreased from 5.0% in the three months ended March 31, 2008 to 3.3% in the same period of 2009. We capitalized $0.5 million in interest costs in the three months ended March 31, 2008 primarily related to the construction of the Spearman and Crossroads plants. In connection with periodic settlements, we recognized $0.8 million in net hedging losses in the three months ended March 31, 2009 and $0.3 million in net hedging gains in the three months ended March 31, 2008 on the Interest Rate Swaps in interest expense.

Derivatives. Our results of operations and operating cash flows were impacted by changes in market prices for NGLs, crude oil and natural gas prices. Commodity markets are volatile, and as a result, our hedging activity results can vary significantly. Our results of operations are affected by the volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. The discounted cash flows utilize discount rates adjusted for the credit risk of our counterparties for derivatives in an asset position, and our own credit risk derivatives in a liability position, in accordance with Statement of Financial Accounting Standards, or SFAS, No. 157, Fair Value Measurements.

In the three months ended March 31, 2009, derivative losses were $7.2 million for changes in fair value and cash received for settlements totaled $2.8 million. In the three months ended March 31, 2008, derivative gains were $7.8 million for changes in fair value and cash paid for settlements totaled $9.5 million.

Our derivative activity for the three months ended March 31, 2009 and 2008 is summarized below:

	Three Months Ended March 31,
	2009			2008
	(in thousands)
Interest Rate Swap unrealized derivative loss	$	(158	)	$	—
Interest Rate Swap realized derivative loss		(956	)		—
Natural gas midstream commodity unrealized derivative gain (loss)		(9,839	)		17,298
Natural gas midstream commodity realized derivative gain (loss)		3,792			(9,522	)
Total derivative gain (loss)	$	(7,161	)	$	7,776

27

Summary of Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.

Coal Royalties Revenues

We recognize coal royalties revenues on the basis of tons of coal sold by our lessees and the corresponding revenues from those sales. Since we do not operate any coal mines, we do not have access to actual production and revenues information until approximately 30 days following the month of production. Therefore, our financial results include estimated revenues and accounts receivable for the month of production. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

Natural Gas Midstream 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 included residue gas sold from processing plants after NGLs were removed, NGLs sold after being removed from system throughput volumes received, condensate collected and sold and gathering and other fees primarily from natural gas volumes connected to our gas processing plants. We recognize revenues from the sale of NGLs and residue gas when we sell the NGLs and residue gas produced at our gas processing plants. We recognize gathering and transportation revenues based upon actual volumes delivered. 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.

Due to the time needed to gather information from various purchasers and measurement locations and then calculate volumes delivered, the collection of natural gas midstream revenues and the calculation of the cost of midstream gas purchased may take up to 30 days following the month of production. Therefore, we make accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable based on estimates of natural gas purchased and NGLs and residue gas sold. We record any differences, which historically have not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

Derivative Activities

From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas, crude oil and NGL price volatility. The derivative financial instruments, which are placed with financial institutions that we believe are acceptable credit risks, take the form of swaps, costless collars and three-way collars. All derivative financial instruments are recognized in our condensed consolidated financial statements at fair value in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. The fair values of our derivative instruments are determined based on discounted cash flows derived from quoted forward prices. All derivative transactions are subject to our risk management policy, which has been reviewed and approved by the board of directors of our general partner.

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 changes in fair value, which fluctuates with changes in interest rates.

Because we do not apply hedge accounting for our commodity derivatives or the Interest Rate Swaps, we recognize changes in fair value in earnings currently in the derivatives line on the condensed consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of unrealized derivative gains or losses recognized due to fluctuations in the value of these commodity derivative contracts. 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. 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.

28

Depreciation, Depletion and Amortization

We compute depreciation and amortization of property, plant and equipment using the straight-line balance method over the estimated useful life of each asset as follows:

	Useful Life
Gathering systems	15-20 years
Compressor stations	5-15 years
Processing plants	15 years
Other property and equipment	3-20 years

Coal properties are depleted on an area-by-area basis at a rate based on the cost of the mineral properties and the number of tons of estimated proven and probable coal reserves contained therein. Proven and probable coal reserves have been estimated by our own geologists and outside consultants. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. From time to time, we carry out core-hole drilling activities on our coal properties in order to ascertain the quality and quantity of the coal contained in those properties. These core-hole drilling activities are expensed as incurred. We deplete timber using a methodology consistent with the units-of-production method, but that is based on the quantity of timber harvested. We determine depletion of oil and gas royalty interests by the units-of-production method and these amounts could change with revisions to estimated proved recoverable reserves. When we retire or sell an asset, we remove its cost and related accumulated depreciation and amortization from our condensed consolidated balance sheets. We record the difference between the net book value, net of any assumed asset retirement obligation, and proceeds from dispositions as a gain or loss on sales of property, plant and equipment.

Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 20 years, the period in which benefits are derived from the contracts, customer relationships and rights-of-way, and are combined with property, plant and equipment and are reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

Fair Value Measurements

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP FAS 157-2”), delayed the application of SFAS No. 157 for nonfinancial assets and liabilities to fiscal years and interim periods beginning after November 15, 2008. Prior to the adoption of FSP FAS 157-2, we only applied fair value measurements to our financial assets and liabilities. Effective January 1, 2009, SFAS No. 157 now applies to both financial and nonfinancial assets and liabilities that are measured and reported on a fair value basis.

SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

• Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Level 1 inputs generally provide the most reliable evidence of fair value.

• Level 2: Quoted prices in markets that are not active or inputs, which are observable, either directly or indirectly, for substantially the full term of the asset or liability.

29

• Level 3: Prices or valuation techniques that require inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity).

We use the following methods and assumptions to estimate the fair values of certain assets and liabilities:

• Interest rate swaps: We have entered into the Interest Rate Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. We use an income approach using valuation techniques that connect future cash flows to a single discounted value. We estimate the fair value of the swaps based on published interest rate yield curves as of the date of the estimate. This is a Level 2 input. See Note 4 – “Derivative Instruments” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements.”

• Commodity derivative instruments: Our natural gas midstream segment’s commodity derivatives utilize three-way collar derivative contracts. We also utilize a combination of costless collar and swap derivative contracts to hedge against the variability in the frac spread. We determine the fair values of our commodity derivative agreements based on discounted cash flows based on quoted forward prices for the respective commodities. This is a Level 2 input. We generally use the income approach, using valuation techniques that convert future cash flows to a single discounted value. See Note 4 – “Derivative Instruments” in the Notes to Condensed Consolidated Financial Statements in Item 1, “Financial Statements.”

Environmental Matters

Our operations and those of our 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 material impact on our financial condition or results of operations.

As of March 31, 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.

Recent Accounting Pronouncements

See Note 2 in the Notes to Condensed Consolidated Financial Statements for a description of recent accounting pronouncements.

Forward-Looking Statements

Certain statements contained herein that are not descriptions of historical facts are “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. 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;

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

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

30

• 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;

• 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.

31

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 recent deterioration of the global economy, including financial and credit markets. At March 31, 2009, we reported a net commodity derivative asset related to the natural gas midstream segment of $12.9 million that is with two 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. No significant uncertainties related to the collectability of amounts owed to us exist with regard to these counterparties.

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

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 business. 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.

In the three months ended March 31, 2009, we reported net derivative losses of $7.2 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 on the condensed consolidated statements of income. We have experienced and could continue to experience significant changes in the estimate of unrealized 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.

32

The following table lists our derivative agreements and their fair values as of March 31, 2009:

	Average Volume Per Day	Weighted Average Price Collars						Fair Value (in thousands)
		Additional Put Option		Put		Call
Crude Oil Three-way Collar	(in barrels)				(per barrel)
Second Quarter 2009 through Fourth Quarter 2009	1,000	$	70.00	$	90.00	$	119.25	$	4,939
Frac Spread Collar	(in MMBtu)				(per MMBtu)
Second Quarter 2009 through Fourth Quarter 2009	6,000			$	9.09	$	13.94		5,594
Settlements to be received in subsequent period									2,366
Natural gas midstream segment commodity derivatives – net asset								$	12,899

We estimate that, excluding the 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 $3.7 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 remainder of 2009 would increase or decrease by approximately $3.8 million. This assumes that crude oil prices, natural gas 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 for a $5.00 per barrel increase in the crude oil price, the fair value of the crude oil three-way collar would decrease by $0.3 million. We estimate that for a $5.00 per barrel decrease in the crude oil price, the fair value of the crude oil three-way collar would increase by $0.2 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 $0.2 million. These estimated changes exclude potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of March 31, 2009, we had $595.1 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 March 31, 2009 would cost us approximately $2.9 million in additional interest expense.

In the first quarter of 2009, we discontinued hedge accounting for all of the Interest Rate Swaps. Accordingly, mark-to-market 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.

Customer Credit Risk

We are exposed to the credit risk of our customers and lessees. Approximately 75%, or $43.2 million, of our consolidated accounts receivable at March 31, 2009 resulted from our natural gas midstream segment and approximately 25%, or $14.0 million, resulted from our coal and natural resource management segment. Approximately $17.4 million of the natural gas midstream

33

segment’s receivables at March 31, 2009 were related to three customers: Conoco, Inc., Tenaska Marketing Ventures, and Louis Dreyfus Energy Services. At March 31, 2009, 40% of our natural gas midstream segment accounts receivable and 30% of our consolidated accounts receivable related to these three natural gas midstream customers. No significant uncertainties related to the collectability of amounts owed to us exist in regards to these three 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 customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations. Any material losses as a result of customer 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 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 uncollectable accounts. As of March 31, 2009, no receivables were collateralized, and we recorded a $1.4 million allowance for doubtful accounts in the natural gas midstream segment

34

Item 4 Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of March 31, 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 March 31, 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.

35

PART II. OTHER INFORMATION

Item 4 Submission of Matters to a Vote of Security Holders

A Special Meeting of Unitholders was held on January 14, 2009. One proposal was voted on and the results of voting on the proposal was as follows:

Amendment and Restatement of the Penn Virginia Resource GP, LLC Fourth Amended and Restated Long-Term Incentive Plan:

For	Against	Abstain	Broker Non-Vote
28,985,703	4,384,325	219,564	0

Item 6 Exhibits

10.1	Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on January 15, 2009).
10.2	Form of Agreement for Phantom Unit Awards under the Penn Virginia Resource GP, LLC Fifth Amended and Restated Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on February 24, 2009).
10.3	First Amendment to Amended and Restated Credit Agreement, dated March 27, 2009, among PVR Finco LLC, the guarantors party thereto, PNC Bank, National Association, as Administrative Agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on March 31, 2009).
10.4	Consolidated Commitment Increase Agreement, dated March 27, 2009 (incorporated by reference to Exhibit 10.2 to Registrant’s Current Report on Form 8-K filed on March 31, 2009).
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.

36

SIGNATURES

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

		PENN VIRGINIA RESOURCE PARTNERS, L.P.
		By: PENN VIRGINIA RESOURCE GP, LLC
Date: May 11, 2009	By:	/s/ Frank A. Pici
		Frank A. Pici
		Vice President and Chief Financial Officer
Date: May 11, 2009	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

37