Penn Virginia Resource Partners, L.P.

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10-Q 1 d10q.htm PENN VIRGINIA RESOURCE PARTNERS, L.P. Penn Virginia Resource Partners, L.P.

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2008

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

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

As of August 6, 2008, 51,798,895 common limited partner units were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX


		Page
PART I. Financial Information

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income for the Three and Six Months Ended June 30, 2008 and 2007	1

	Condensed Consolidated Balance Sheets as of June 30, 2008 and December 31, 2007	2

	Condensed Consolidated Statements of Cash Flows for the Three and Six Months Ended June 30, 2008 and 2007	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	33

Item 4.	Controls and Procedures	36

PART II. Other Information

Item 6.	Exhibits	37

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Revenues
Natural gas midstream	$	234,797		$	114,407		$	359,845		$	209,725
Coal royalties		31,641			24,029			55,603			49,029
Coal services		1,841			2,092			3,703			3,693
Other		8,226			3,616			14,168			5,897

Total revenues		276,505			144,144			433,319			268,344

Expenses
Cost of midstream gas purchased		202,819			95,077			302,516			174,808
Operating		8,719			5,497			15,512			11,011
Taxes other than income		976			603			2,048			1,446
General and administrative		6,743			5,763			13,261			11,402
Depreciation, depletion and amortization		12,919			9,822			24,419			19,955

Total expenses		232,176			116,762			357,756			218,622

Operating income		44,329			27,382			75,563			49,722

Other income (expense)
Interest expense		(5,374	)		(3,617	)		(10,306	)		(7,164	)
Interest income and other		458			345			920			632
Derivatives		(29,942	)		(7,550	)		(22,166	)		(10,197	)

Net income	$	9,471		$	16,560		$	44,011		$	32,993

General partner’s interest in net income	$	4,569		$	2,940		$	9,196		$	5,434

Limited partners’ interest in net income	$	4,902		$	13,620		$	34,815		$	27,559

Basic and diluted net income per limited partner unit (see Note 7)	$	0.10		$	0.30		$	0.73		$	0.60

Weighted average number of units outstanding, basic and diluted		48,581			46,107			47,521			46,102

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

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)


	June 30, 2008			December 31, 2007
Assets
Current assets
Cash and cash equivalents	$	17,832		$	19,530
Accounts receivable		135,442			78,888
Derivative assets		4,795			1,212
Other current assets		4,558			4,104

Total current assets		162,627			103,734

Property, plant and equipment		944,951			877,571
Accumulated depreciation, depletion and amortization		(168,440	)		(146,289	)

Net property, plant and equipment		776,511			731,282

Equity investments		77,222			25,640
Goodwill		7,718			7,718
Intangibles, net		27,196			28,938
Other long-term assets		49,937			33,967

Total assets	$	1,101,211		$	931,279

Liabilities and Partners’ Capital
Current liabilities
Accounts payable	$	117,801		$	65,483
Accrued liabilities		14,244			10,753
Current portion of long-term debt		58,083			12,561
Deferred income		3,099			2,958
Derivative liabilities		43,396			41,733

Total current liabilities		236,623			133,488
Deferred income		8,303			6,889
Other liabilities		18,496			19,158
Derivative liabilities		6,642			1,315
Long-term debt		323,100			399,153
Partners’ capital		508,047			371,276

Total liabilities and partners’ capital	$	1,101,211		$	931,279

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

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
Cash flows from operating activities
Net income	$	9,471		$	16,560		$	44,011		$	32,993
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		12,919			9,822			24,419			19,955
Commodity derivative contracts:
Total derivative losses		31,459			8,835			24,791			12,325
Cash settlements of derivatives		(9,703	)		(2,189	)		(19,225	)		(4,261	)
Non-cash interest expense		204			165			368			330
Equity earnings, net of distributions received		354			(645	)		(6	)		(878	)
Other		(312	)		(198	)		(621	)		(198	)
Changes in operating assets and liabilities		89			1,448			(410	)		(2,950	)

Net cash provided by operating activities		44,481			33,798			73,327			57,316

Cash flows from investing activities
Acquisitions		(96,220	)		(52,117	)		(96,240	)		(52,456	)
Additions to property, plant and equipment		(21,190	)		(11,872	)		(38,840	)		(18,874	)
Other		334			154			675			197

Net cash used in investing activities		(117,076	)		(63,835	)		(134,405	)		(71,133	)

Cash flows from financing activities
Distributions to partners		(25,640	)		(21,951	)		(50,358	)		(42,980	)
Proceeds from borrowings		99,800			52,000			124,800			62,000
Repayments of borrowings		(132,400	)		—			(155,400	)		(5,000	)
Net proceeds from issuance of partners’ capital		140,958			—			140,958			—
Other		(620	)		—			(620	)		860

Net cash provided by financing activities		82,098			30,049			59,380			14,880

Net increase (decrease) in cash and cash equivalents		9,503			12			(1,698	)		1,063
Cash and cash equivalents – beginning of period		8,329			12,491			19,530			11,440

Cash and cash equivalents – end of period	$	17,832		$	12,503		$	17,832		$	12,503

Supplemental disclosure:
Cash paid for interest	$	4,249		$	2,369		$	10,372		$	6,903

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

June 30, 2008

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: (1) coal and natural resource management and (2) 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. We also earn revenues from other land management activities, such as selling standing timber and real estate rentals, 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 the Texas Panhandle. In July 2008, we acquired natural gas midstream assets in the Fort Worth Basin of North Texas. See Note 14 – Subsequent Events. 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. 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 June 30, 2008, Penn Virginia owned an approximately 82% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At June 30, 2008, 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, 2007. 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. Our condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. 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 condensed consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007. Operating results for the three and six months ended June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

New Accounting Standards

In March 2008, the Emerging Issues Task Force (“EITF”) ratified EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships, (“EITF 07-4”) which states that incentive distribution rights (“IDRs”) in a typical master limited partnership are participating securities under Statement of Financial Accounting Standards (“SFAS”)

No. 128, Earnings Per Share. According to EITF 07-4, when current-period earnings exceed cash distributions and the IDR is embedded in the general partner interest, undistributed earnings should not be allocated to the general partner (including embedded IDRs) and limited partners. Under the current accounting guidance, when current-period earnings exceed cash distributions and the IDR is embedded in the general partner interest, undistributed earnings should be allocated to the general partner. For the three and six months ended June 30, 2008 and 2007, current-period earnings did not exceed cash distributions. See Note 7 – Partners’ Capital and Distributions. EITF 07-4 will be effective for fiscal years beginning after December 15, 2008 and applied retrospectively to all periods presented. Early application is not permitted. EITF 07-4 will eliminate our need to adjust our earnings per unit calculation in periods where current period earnings exceed distributions.

In April 2008, the Financial Accounting Standards Board (“FASB”) issued Staff Position No. FAS 142-3, Determination of the Useful Life of Intangible Assets (“FSP FAS 142-3”) which amends SFAS No. 142, Goodwill and Other Intangible Assets. The pronouncement requires companies estimating the useful life of a recognized intangible asset to consider their historical experience in renewing or extending similar arrangements or, in the absence of historical experience, to consider assumptions that market participants would use about renewal or extension. FSP FAS 142-3 is effective for financial statements issued for fiscal years and interim periods beginning after December 15, 2008 and must be applied prospectively to intangible assets acquired after the effective date. We will prospectively apply FSP FAS 142-3 to all intangible assets purchased after January 1, 2009.

3. Acquisition

In April 2008, we acquired 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 for $51.6 million in cash, after customary closing adjustments. Funding for the acquisition was provided by borrowings under our revolving credit facility (the “Revolver”). The entire member interest is recorded in equity investments on the condensed consolidated balance sheet. This investment includes $37.3 million of fair value for the net assets acquired and $14.3 million of fair value paid in excess of our portion of the underlying equity in the net assets acquired related to customer contracts and related customer relations. This excess is being amortized to equity earnings over the life of the underlying contracts. The earnings are recorded in other revenues on the condensed consolidated income statement.

4. Unit Offering

In the second quarter of 2008, we issued 5.15 million common limited partner units to the public representing limited partner interests and received $138.1 million in net proceeds. We received total contributions of $2.9 million from our general partner in order to maintain its 2% general partner interest. The net proceeds were used to repay a portion of our borrowings under the Revolver.

5. Fair Value Measurement of Financial Instruments

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being 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. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, delays the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008.

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).

The following table summarizes the valuation of our financial instruments by the above SFAS No. 157 categories as of June 30, 2008 (in thousands):


				Fair Value Measurement at June 30, 2008, Using
Description	Fair Value Measurements, June 30, 2008			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	$	(958	)	$	—	$	(958	)	$	—
Interest rate swap liability - noncurrent		(1,420	)		—		(1,420	)		—
Commodity derivative assets - current		4,795			—		4,795			—
Commodity derivative liability - current		(42,438	)		—		(42,438	)		—
Commodity derivative liability - noncurrent		(5,222	)		—		(5,222	)		—

Total	$	(45,243	)	$	—	$	(45,243	)	$	—

We use the following methods and assumptions to estimate the fair values in the above table:

•

Commodity derivative instruments: The fair values of our commodity derivative agreements are determined based on forward price quotes 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. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 6 – Derivative Instruments.

•

Interest rate swaps: We have entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the Revolver. 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. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 6 – Derivative Instruments.

6. Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize costless collar, three-way collar and swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. We also utilize swap derivative 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 the natural gas liquids, or NGLs, that we sell after processing. We hedge against the variability in our frac spread by entering into swap derivative contracts to sell NGLs forward at a predetermined swap 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, their use also may limit future revenues or cost savings from favorable price movements.

With respect to a costless collar contract, the counterparty 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 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. With respect to a swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

A three-way collar is a combination of options: a sold call, a purchased put and a sold put. The sold call establishes the maximum price that we will receive for the contracted commodity volumes. The purchased put establishes the minimum price that we will receive for the contracted volumes unless the market price for the commodity falls below the sold put strike price, at which point the minimum price equals the reference price (i.e., NYMEX) plus the excess of the purchased put strike price over the sold put strike price.

The fair values of our derivative agreements are determined based on forward price quotes for the respective commodities as of June 30, 2008, the credit risks of our counterparties and our own credit risk. The following table sets forth our positions as of June 30, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased (in thousands):


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Estimated Fair Value
	Average Volume Per Day		Weighted Average Price			Additional Put Option		Put		Call		Estimated Fair Value
Frac Spread	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(5,944	)

Ethane Sale Swap	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,774	)

Propane Sale Swaps	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,675	)

Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Third Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(9,334	)

Natural Gasoline Collar	(in gallons	)							(per gallon)
Third Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(1,611	)

Crude Oil Collar	(in barrels	)							(per barrel)
Third Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(4,784	)

Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									4,795

Crude Oil Three-Way Collar	(in barrels	)							(per gallon)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		(10,292	)

Frac Spread Collar (1)	(in MMBtu	)							(in MMBtu)
First Quarter 2009 through Fourth Quarter 2009	6,000							$	9.09	$	13.94		—

Settlements to be paid in subsequent period													(5,246	)

Natural gas midstream segment commodity derivatives - net liability												$	(42,865	)

(1)	We entered into this contract in July 2008.

At June 30, 2008, we reported a (i) net derivative liability related to the natural gas midstream segment of $42.9 million and (ii) loss in accumulated other comprehensive income (“AOCI”) of $2.9 million related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006. The $2.9 million loss will be recorded in earnings through the end of 2008 as the hedged transactions settle. Reference the Adoption of SFAS No. 161 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 Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $100.0 million. Until March 2010, we will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). From March 2010 to December 2011, we will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as

interest expense. The Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings as interest income (expense). We reported a (i) derivative liability of $2.4 million at June 30, 2008 and (ii) loss in accumulated other comprehensive income of $2.4 million at June 30, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.6 million and $0.4 million in net hedging losses in interest expense for the three and six months ended June 30, 2008.

Adoption of SFAS No. 161

In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an Amendment of FASB Statement No. 133, which amends and expands SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. We elected to adopt SFAS No. 161 early, effective June 30, 2008. SFAS No. 161 requires companies to disclose how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows.

The following table summarizes the effects of derivative activities, as well as the location of the gains and losses, on our condensed consolidated statements of income for the three and six months ended June 30, 2008 (in thousands):


	Location of gain (loss) on derivatives recognized in income	Three Months Ended			Six Months Ended
		June 30, 2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts (1)	Interest expense	$	(626	)	$	(359	)

Decrease in net income resulting from derivatives designated as hedging instruments under SFAS No. 133		$	(626	)	$	(359	)

Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts (1)	Natural gas midstream revenues	$	(1,997	)	$	(4,248	)
Commodity contracts (1)	Cost of midstream gas purchased		480			1,623
Commodity contracts	Derivatives		(29,942	)		(22,166	)

Decrease in net income resulting from derivatives not designated as hedging instruments under SFAS No. 133		$	(31,459	)	$	(24,791	)

Total decrease in net income resulting from derivatives		$	(32,085	)	$	(25,150	)

Realized and unrealized derivative impact:
Cash paid for commodity contract settlements	Derivatives		(9,703	)		(19,225	)
Cash received (paid) for interest rate contract settlements	Interest expense		(626	)		(359	)
Unrealized derivative loss	(2)		(21,756	)		(5,566	)

Total decrease in net income resulting from derivatives		$	(32,085	)	$	(25,150	)

(1)

These amounts represent reclassifications from AOCI. Subsequent to the discontinuation of hedge accounting for commodity derivatives in 2006, amounts remaining in AOCI have been reclassified into earnings in the same period or periods during which the original hedge forecasted transaction affects earnings. The amount remaining in AOCI that will be reclassified to earnings in future periods is $2.9 million.

(2)

This activity represents unrealized losses in the natural gas midstream, cost of midstream gas purchased and derivatives lines on our condensed consolidated statements of income.

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


	Balance Sheet Location	Derivative Assets		Derivative Liabilities
		Fair values as of June 30, 2008
Derivatives designated as hedging instruments under SFAS No. 133:
Interest rate contracts	Derivative liabilities - current	$	—	$	958
Interest rate contracts	Derivative liabilities - noncurrent		—		1,420

Total derivatives designated as hedging instruments under SFAS No. 133		$	—	$	2,378

Derivatives not designated as hedging instruments under SFAS No. 133:
Commodity contracts	Derivative assets/liabilities - current	$	4,795	$	42,438
Commodity contracts	Derivative liabilities - noncurrent		—		5,222

Total derivatives not designated as hedging instruments under SFAS No. 133		$	4,795	$	47,660

Total fair values of derivative instruments		$	4,795	$	50,038

The following table summarizes the effect of the Revolver Swaps on our total interest expense for the three and six months ended June 30, 2008 (in thousands):


	Three Months Ended			Six Months Ended
Source	June 30, 2008
Borrowings	$	(4,935	)	$	(10,622	)
Capitalized interest (1)		187			675
Interest rate swaps		(626	)		(359	)

Total interest expense	$	(5,374	)	$	(10,306	)

(1)	Capitalized interest for the three and six months ended June 30, 2008 was primarily related to the construction of our natural gas gathering facilities.

The above derivative activity represents cash flow hedges. As of June 30, 2008, none of our derivative instruments were classified as fair value hedges, nor were any derivative instruments classified as trading securities. In addition, as of June 30, 2008, none of our derivative instruments contained credit risk contingencies.

7. Partners’ Capital and Distributions

As of June 30, 2008, partners’ capital consisted of 51.3 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of June 30, 2008, affiliates of Penn Virginia, in the aggregate, owned a 40% interest in us, consisting of 19.6 million common units and a 2% general partner interest.

Subordinated Units

Until May 22, 2007, we had Class B units, a separate class of subordinated units representing limited partner interests in us, that were issued to PVG in connection with PVG’s initial public offering. On May 22, 2007, all of our Class B units automatically converted into common units on a one-for-one basis and no Class B units remain outstanding.

Net Income per Limited Partner Unit

EITF Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128 (“EITF 03-6”) addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. EITF 03-6 provides that in any accounting period where our net income exceeds our distribution for such period, we are required to present net income per limited partner unit as if all of the net income for the period was distributed, regardless of the pro forma nature of this allocation and whether that net income would actually be distributed during a particular period from an economic or practical perspective. In this instance, basic and diluted net income per limited partner unit is determined by dividing net income available to limited partners by the weighted average number of limited partner units outstanding during the period. To calculate net income available to limited partners, income is first allocated to our general partner based on the amount of incentive distributions to which it is entitled and the remainder is allocated between the limited partners and our general partner based on their percentage ownership interests in us.

We make cash distributions on the basis of cash available for distributions, not net income, in any given accounting period. In accounting periods where our net income does not exceed our distributions for such period, EITF 03-6 does not apply and basic and diluted net income per limited partner unit is determined by dividing net income by the weighted average number of limited partner units outstanding during the period.

The following table reconciles net income and weighted average limited partner units used in computing basic and diluted net income per limited partner unit:


	Three Months Ended June 30,						Six Months Ended June 30,
	2008			2007			2008			2007
	(in thousands, except per unit data)						(in thousands, except per unit data)
Net income	$	9,471		$	16,560		$	44,011		$	32,993
Less: General partner’s incentive distributions paid		(4,469	)		(2,662	)		(8,486	)		(4,872	)

Subtotal		5,002			13,898			35,525			28,121
General partner interest in net income		(100	)		(278	)		(710	)		(562	)

Net income available to limited partners under EITF 03-6	$	4,902		$	13,620		$	34,815		$	27,559

Weighted average limited partner units, basic and diluted		48,581			46,107			47,521			46,102
Basic and diluted net income per limited partner unit	$	0.10		$	0.30		$	0.73		$	0.60

Cash Distributions

We distribute 100% of Available Cash (as defined in our partnership agreement) within 45 days after the end of each quarter to unitholders of record and to our general partner. Available Cash is generally defined as all of our cash and cash equivalents on hand at the end of each quarter less reserves established by our general partner for future requirements. Our general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or 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:


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

The following table reflects the allocation of total cash distributions paid by us during the three and six months ended June 30, 2008 and 2007:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(in thousands, except per unit data)				(in thousands, except per unit data)
Limited partner units	$	20,748	$	18,903	$	41,035	$	37,346
General partner interest (2%)		423		386		837		762
Incentive distribution rights		4,469		2,662		8,486		4,872

Total cash distributions paid	$	25,640	$	21,951	$	50,358	$	42,980

Total cash distributions paid per unit	$	0.45	$	0.41	$	0.89	$	0.81

On February 14, 2008, the board of directors of our general partner paid a quarterly distribution of $0.44 per unit to our unitholders ($1.76 per unit on an annualized basis). On May 15, 2008, the board of directors of our general partner paid a $0.45 per unit quarterly distribution to our unitholders ($1.80 per unit on an annualized basis). In July 2008, the board of directors of our general partner declared a quarterly distribution of $0.46 per unit, or $1.84 per unit on an annualized basis, for the three months ended June 30, 2008. The distribution will be paid on August 14, 2008 to unitholders of record at the close of business on August 4, 2008.

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of the remaining common units at a price not less than the then current market price of the common units.

8. Senior Notes Repayment

In June 2008, we notified the holders of our Senior Unsecured Notes due 2013 (the “Notes”) that we would prepay 100% of the aggregate principal amount of the Notes as provided in the Note Purchase Agreements governing the Notes. In July 2008, we paid an aggregate of $63.3 million to the noteholders, which amount consists of approximately $58.4 million aggregate principal amount outstanding on the Notes, $1.1 million in accrued and unpaid interest on the Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the Notes. The Notes were repaid with borrowings under the Revolver. As a result of calling the Notes in June 2008, we reclassified the Notes to the current liabilities section of our condensed consolidated balance sheets.

9. Related-Party Transactions

General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us and our subsidiaries totaled $1.6 million and $1.4 million for the three months ended June 30, 2008 and 2007 and $3.1 million and $2.6 million for the six months ended June 30,

2008 and 2007. 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 $17.7 million and $2.4 million as of June 30, 2008 and December 31, 2007. The increase in the balance in the six months ended June 30, 2008 is due primarily to amounts due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (“PVOG”) related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (“PVR East Texas”) and PVOG. See “– Gathering and Processing Revenues.” These balances are included in accounts payable on our condensed consolidated balance sheets.

Marketing Revenues

PVOG and Connect Energy Services, LLC (“Connect Energy”), our wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG and Connect Energy have agreed that Connect Energy will market all of PVOG’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 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 paid fees to Connect Energy of $0.8 million and $0.6 million for the three months ended June 30, 2008 and 2007 and $1.5 million and $1.0 million for the six months ended June 30, 2008 and 2007. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

Gathering and Processing Revenues

PVR East Texas and PVOG are parties to a natural gas gathering and processing agreement effective during the first quarter of 2008. PVR East Texas will gather and process the natural gas delivered by PVOG. Connect Energy will purchase the processed gas and plant products (NGLs) from PVOG and sell them to third parties. PVOG paid PVR East Texas plant $0.7 million in the six months ended June 30, 2008 for gathering and processing fees. These gathering and processing revenues are recorded in the natural gas midstream line on our condensed consolidated statements of income. Connect Energy purchased processed gas and plant products from PVOG for $49.8 million in the six months ended June 30, 2008.

Purchase of PVG Units

In July 2008, we acquired natural gas midstream assets in the Forth Worth Basin in North Texas. Part of the consideration given by us in this transaction was 2.0 million PVG common units, which we purchased from two subsidiaries of Penn Virginia. See Note 14 – Subsequent Events.

10. Unit-Based Compensation

We recognized a total of $0.7 million and $0.6 million for the three months ended June 30, 2008 and 2007 and $1.5 million and $1.1 million for the six months ended June 30, 2008 and 2007 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 six months ended June 30, 2008, 131,551 restricted units with a weighted average grant date fair value of $26.93 per unit were granted to employees of Penn Virginia and its affiliates. During the same period, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted in 2008 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.

11. 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 and six months ended June 30, 2008 and 2007:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008			2007
	(in thousands)				(in thousands)
Net income	$	9,471	$	16,560	$	44,011		$	32,993
Unrealized holding losses on derivative activities		4,318		771		(825	)		571
Reclassification adjustment for derivative activities		2,143		1,112		2,984			1,784

Comprehensive income	$	15,932	$	18,443	$	46,170		$	35,348

12. 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, liquidity or operations.

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 June 30, 2008 and December 31, 2007, our environmental liabilities included $1.3 million and $1.5 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.

13. 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 and real estate rentals; 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.

The following tables present a summary of certain financial information relating to our segments as of and for the three and six months ended June 30, 2008 and 2007:


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Three Months Ended June 30, 2008:
Revenues	$	39,056	$	237,449	$	276,505
Cost of midstream gas purchased		—		202,819		202,819
Operating costs and expenses		7,547		8,891		16,438
Depreciation, depletion and amortization		7,526		5,393		12,919

Operating income	$	23,983	$	20,346		44,329

Interest expense, net						(4,916	)
Derivatives						(29,942	)

Net income					$	9,471

Total assets	$	697,758	$	403,453	$	1,101,211
Equity investments (1)	$	25,030	$	52,192	$	77,222
Additions to property and equipment and acquisitions	$	24,641	$	92,769	$	117,410

For the Three Months Ended June 30, 2007:
Revenues	$	28,410	$	115,734	$	144,144
Cost of midstream gas purchased		—		95,077		95,077
Operating costs and expenses		5,524		6,339		11,863
Depreciation, depletion and amortization		5,320		4,502		9,822

Operating income	$	17,566	$	9,816		27,382

Interest expense, net						(3,272	)
Derivatives						(7,550	)

Net income					$	16,560

Total assets	$	362,383	$	405,691	$	768,074
Equity investments	$	26,173	$	60	$	26,233
Additions to property and equipment and acquisitions	$	52,130	$	11,859	$	63,989

(1)	This increase in equity investments is due to our 25% member interest in Thunder Creek that we acquired in the second quarter of 2008 for $51.6 million. See Note 3 – Acquisition.


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Six Months Ended June 30, 2008:
Revenues	$	69,350	$	363,969	$	433,319
Cost of midstream gas purchased		—		302,516		302,516
Operating costs and expenses		13,846		16,975		30,821
Depreciation, depletion and amortization		13,939		10,480		24,419

Operating income	$	41,565	$	33,998		75,563

Interest expense, net						(9,386	)
Derivatives						(22,166	)

Net income					$	44,011

Total assets	$	697,758	$	403,453	$	1,101,211
Equity investments (1)	$	25,030	$	52,192	$	77,222
Additions to property and equipment and acquisitions	$	24,689	$	110,391	$	135,080

For the Six Months Ended June 30, 2007:
Revenues	$	56,894	$	211,450	$	268,344
Cost of midstream gas purchased		—		174,808		174,808
Operating costs and expenses		10,618		13,241		23,859
Depreciation, depletion and amortization		10,810		9,145		19,955

Operating income	$	35,466	$	14,256		49,722

Interest expense, net						(6,532	)
Derivatives						(10,197	)

Net income					$	32,993

Total assets	$	362,383	$	405,691	$	768,074
Equity investments	$	26,173	$	60	$	26,233
Additions to property and equipment and acquisitions	$	53,466	$	17,864	$	71,330

(1)	This increase in equity investments is due to our 25% member interest in Thunder Creek that we acquired in the second quarter of 2008 for $51.6 million. See Note 3 – Acquisition.

14. Subsequent Events

On July 17, 2008, we completed an acquisition of Lone Star Gathering, L.P. in the Fort Worth Basin of North Texas, which included gas gathering and transportation equipment. We acquired this business for approximately $160.0 million and a $5.0 million payment guarantee at a later date, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.0 million of borrowings under the Revolver, 2.0 million PVG common units (which we purchased from two subsidiaries of Penn Virginia) and 0.5 million of our newly issued common units. The contingent payments will be triggered if a defined geographic area in which a subset of the acquired assets are located reaches certain revenue targets by or before June 30, 2013 and will be funded in cash or common units, at our election.

On August 5, 2008, we amended and restated the Revolver to increase our available borrowings under the Revolver from $600.0 million to $700.0 million and to make it a secured facility. The Revolver is secured by substantially all of our assets.

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: (1) coal and natural resource management and (2) natural gas midstream. Our operating income was $75.6 million for the six months ended June 30, 2008, compared to $49.7 million for the six months ended June 30, 2007. In the six months ended June 30, 2008, our coal and natural resource management segment contributed $41.6 million, or 55%, to operating income, and our natural gas midstream segment contributed $34.0 million, or 45%, to operating income.

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


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Six Months Ended June 30, 2008:
Revenues	$	69,350	$	363,969	$	433,319
Cost of midstream gas purchased		—		302,516		302,516
Operating costs and expenses		13,846		16,975		30,821
Depreciation, depletion and amortization		13,939		10,480		24,419

Operating income	$	41,565	$	33,998	$	75,563


For the Six Months Ended June 30, 2007:
Revenues	$	56,894	$	211,450	$	268,344
Cost of midstream gas purchased		—		174,808		174,808
Operating costs and expenses		10,618		13,241		23,859
Depreciation, depletion and amortization		10,810		9,145		19,955

Operating income	$	35,466	$	14,256	$	49,722

Coal and Natural Resource Management Segment

As of December 31, 2007, we owned or controlled 818 million tons of proven and probable coal reserves in Central and Northern Appalachia, the San Juan Basin and the Illinois Basin. We enter into long-term leases with experienced, third-party mine operators, providing them the right to mine our coal reserves in exchange for royalty payments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We do not operate any mines. In the six months ended June 30, 2008, our lessees produced 16.5 million tons of coal from our properties and paid us coal royalties revenues of $55.6 million, for an average royalty per ton of $3.37. Approximately 86% of our coal royalties revenues in the six months ended June 30, 2008 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. The global markets for most types of coal remain strong. Continued demand from emerging countries and the increased consumption domestically have created a strong global picture. During 2007 and 2008, U.S.-produced coal enjoyed increased demand abroad as dwindling supplies and the decline of the dollar made U.S.-exported coal more attractive.

We also earn revenue from the provision of fee-based coal preparation and loading services, from the sale of standing timber on our properties, from oil and gas royalty interests we own and from coal transportation, or wheelage, fees.

Our management continues to focus on acquisitions that increase and diversify our sources of cash flow.

Natural Gas Midstream Segment

We own and operate natural gas midstream assets located in Oklahoma, the Texas Panhandle and East Texas. These assets included approximately 3,863 miles of natural gas gathering pipelines as of June 30, 2008. In July 2008, we completed the Lonestar acquisition, in which we acquired approximately 132 additional miles of gas gathering pipelines in the Fort Worth Basin in North Texas. See Note 14 – Subsequent Events in Item 1, “Financial Statements,” of the Condensed Consolidated Financial Statements. 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. 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 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.

For the six months ended June 30, 2008, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 41.2 Bcf, or approximately 226 MMcfd. For the six months ended June 30, 2008, one of our natural gas midstream customers accounted for 24% of our natural gas midstream revenues and 20% of our total consolidated revenues.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty.

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.

Liquidity and Capital Resources

We generally satisfy our working capital requirements and fund our capital expenditures and debt service obligations from cash generated from our operations and borrowings under our revolving credit facility (the “Revolver”). We believe that the cash generated from our operations and our borrowing capacity will be sufficient to meet our working capital requirements, anticipated capital

expenditures (other than major capital improvements or acquisitions), scheduled debt payments and distribution payments. See Note 7 – Partners’ Capital and Distributions in Item 1, “Financial Statements,” of the Condensed Consolidated 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, among other things, prevailing economic conditions in the coal industry and natural gas midstream market, some of which are beyond our control.

Cash Flows

The following table summarizes our cash flow statements for the six months ended June 30, 2008 and 2007 (in thousands):


For the Six Months Ended June 30, 2008	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
Cash flows from operating activities:
Net income contribution	$	31,288		$	12,723		$	44,011
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		14,199			15,527			29,726
Net change in operating assets and liabilities		(82,628	)		82,218			(410	)

Net cash provided by (used in) operating activities	$	(37,141	)	$	110,468			73,327

Net cash used in investing activities	$	(24,014	)	$	(110,391	)		(134,405	)

Net cash provided by financing activities								59,380

Net decrease in cash and cash equivalents							$	(1,698	)


For the Six Months Ended June 30, 2007	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
Cash flows from operating activities:
Net income contribution	$	28,521		$	4,472		$	32,993
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		10,064			17,209			27,273
Net change in operating assets and liabilities		(5,523	)		2,573			(2,950	)

Net cash provided by operating activities	$	33,062		$	24,254			57,316

Net cash used in investing activities	$	(53,269	)	$	(17,864	)		(71,133	)

Net cash provided by financing activities								14,880

Net increase in cash and cash equivalents							$	1,063

Cash provided by operating activities increased by $16.0 million, or 28%, from $57.3 million in the six months ended June 30, 2007 to $73.3 million in the same period of 2008. This increase was primarily attributable to the increase in our natural gas midstream segment’s operating income, partially offset by increased cash outflows for derivative settlements.

Capital Expenditures

The following table sets forth capital expenditures by segment during the six months ended June 30, 2008 and 2007:


	Six Months Ended June 30,
	2008		2007
	(in thousands)
Coal and natural resource management
Acquisitions	$	24,579	$	52,456
Expansion capital		—		52
Other property and equipment		110		85

Total		24,689		52,593

Natural gas midstream
Acquisitions		67,651		—
Expansion capital		35,026		12,540
Other property and equipment		7,031		4,635

Total		109,708		17,175

Total capital expenditures	$	134,397	$	69,768

In the six months ended June 30, 2008, our natural gas midstream segment made aggregate capital expenditures of $109.7 million, primarily related to our 25% member interest acquisition of Thunder Creek, a deposit paid in connection with the acquisition of Lone Star Gathering, L.P. (“Lone Star Acquisition”) and expansion capital expenditures related to the Spearman Natural Gas Processing Plant in the Texas Panhandle (“Spearman plant”) and Crossroads Natural Gas Processing Plant in East Texas (“Crossroads plant”).

In April 2008, our natural gas midstream segment acquired a gathering business in north Texas for approximately $7.8 million, which expanded our existing gathering system in the Beaver/Perryton area. In May 2008, our coal and natural resource management segment acquired approximately 29 million tons of coal reserves and an estimated 56 million board feet of hardwood timber in western Virginia and eastern Kentucky for approximately $24.5 million, after customary closing adjustments. These acquisitions were funded by borrowings under the Revolver.

In the six months ended June 30, 2007, our coal and natural resource management segment made aggregate capital expenditures of $52.6 million, primarily related to acquisitions of coal reserves, a preparation plant and coal handling facilities. In the six months ended June 30, 2007, our natural gas midstream segment made aggregate capital expenditures of $17.2 million, primarily for natural gas midstream system expansion projects.

We funded our coal and natural resource management and natural gas midstream capital expenditures in the six months ended June 30, 2008 and 2007, primarily with cash provided by operating activities and borrowings under the Revolver.

Distributions to partners increased to $50.4 million in the six months ended June 30, 2008 from $43.0 million in the six months ended June 30, 2007, because we increased the quarterly unit distribution from $0.41 per unit to $0.44 per unit.

We had net repayments of $30.6 million in the six months ended June 30, 2008, comprised of net repayments of $24.6 million under the Revolver and net repayments of $6.0 million under the Senior Unsecured Notes due 2013 (the “Notes”). We received net proceeds of $138.1 million from the sale of our common units in a public offering in the second quarter of 2008 and $2.9 million in contributions from our general partner to maintain its 2% general partner interest. These proceeds and contributions were partially offset by capital expenditures of $134.4 million in the six months ended June 30, 2008. This is compared to $57.0 million of net borrowings in the six months ended June 30, 2007, comprised of net borrowings of $62.0 million under the Revolver and net repayments of $5.0 million under our Senior Unsecured Notes due 2013 (the “Notes”). Funds from the borrowings in the six months ended June 30, 2007 were primarily used for capital expenditures.

Long-Term Debt

As of June 30, 2008, we had outstanding borrowings of $381.5 million, consisting of $323.1 million borrowed under the Revolver and $58.1 million due under the Notes. The current portion of the Notes as of June 30, 2008 was $58.1 million.

Revolving Credit Facility. As of June 30, 2008, we had $323.1 million outstanding under the Revolver that matures in December 2011. On April 9, 2008, the available borrowings under the Revolver increased to $600.0 million. The Revolver 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. We had outstanding letters of credit of $1.6 million as of June 30, 2008. At the current $600.0 million limit on the Revolver, and given the outstanding balance of $323.1 million, net of $1.6 million of letters of credit, we could borrow up to $275.3 million. In August 2008, we increased our available borrowings under the Revolver from $600.0 million to $700.0 million and secured the Revolver with substantially all of our assets. In the six months ended June 30, 2008, we incurred commitment fees of $0.2 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 0.75% if we select the base rate borrowing option under the Revolver or at a rate derived from LIBOR, plus an applicable margin ranging from 0.75% to 1.75% if we select the LIBOR-based borrowing option. The weighted average interest rate on borrowings outstanding under the Revolver in the six months ended June 30, 2008 was 4.6%.

The financial covenants under the Revolver require us not to exceed specified debt-to-consolidated EBITDA and consolidated EBITDA-to-interest expense ratios. The Revolver prohibits us from making distributions to our partners if any potential default, or event of default, as defined in the Revolver, occurs or would result from the distributions. In addition, the Revolver contains various covenants that limit, among other things, our ability to incur indebtedness, grant liens, make certain loans, acquisitions and investments, make any material change to the nature of our business, acquire another company or enter into a merger or sale of assets, including the sale or transfer of interests in our subsidiaries. As of June 30, 2008, we were in compliance with all of our covenants under the Revolver.

The Notes. As of June 30, 2008, we owed $58.1 million under the Notes. The Notes bore interest at a fixed rate of 6.02% and were scheduled to mature in March 2013, with semi-annual principal and interest payments. The Notes were equal in right of payment with all of our other unsecured indebtedness, including the Revolver.

In June 2008, we notified the holders of the Notes that we would prepay 100% of the aggregate principal amount of the Notes as provided in the Notes Purchase Agreements governing the Notes. In July 2008, we paid an aggregate of $63.3 million to the noteholders, which amount consists of approximately $58.4 million aggregate principal amount outstanding on the Notes, $1.1 million in accrued and unpaid interest on the Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the Notes. The Notes were repaid with borrowings under the Revolver. As a result of calling the Notes in June 2008, we reclassified them to the current liabilities section of our condensed consolidated balance sheets.

Interest Rate Swaps. We have entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Revolver Swaps total $160.0 million. From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $100.0 million. Until March 2010, we will pay a weighted average fixed rate of 4.33% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. From March 2010 to December 2011, we will pay a weighted average fixed rate of 4.40% on the notional amount, and the counterparties will pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the swap transactions is recorded each period in other comprehensive income. The ineffective portion of the change in fair value, if any, is recorded to current period earnings in interest expense. After considering the applicable margin of 1.25% in effect as of June 30, 2008, the total interest rate on the $160.0 million portion of Revolver borrowings covered by the Revolver Swaps was 5.58% at June 30, 2008. In August 2008, we entered into an additional interest rate swap with a notional amount of $50.0 million. We will pay a weighted average interest rate of 3.877% on the notional amount, and the counterparties will pay a variable rate equal to the three month LIBOR.

Unit Offering

Future Capital Needs and Commitments

Part of our strategy is to make acquisitions and other capital expenditures which increase cash available for distribution to our unitholders. Our ability to make these acquisitions in the future will depend in part on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units, which will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating. For the remainder of 2008, in addition to the acquisitions mentioned above and in the subsequent events footnote to the financial statements included in this filing, we anticipate making capital expenditures, excluding acquisitions, of $7.5 million, consisting of $2.2 million in the coal and natural resource management segment and $5.3 million in the natural gas midstream segment. We intend to fund these capital expenditures with a combination of cash flows provided by operating activities, borrowings under the Revolver and possibly with the issuance of additional debt securities. We make quarterly cash distributions of our available cash, generally defined as all of our cash and cash equivalents on hand at the end of each quarter less cash reserves. We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Short-term cash requirements, such as operating expenses and quarterly distributions to our general partner and unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for asset acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities.

Results of Operations

Selected Financial Data—Consolidated

The following table sets forth a summary of certain consolidated financial data for the three and six months ended June 30, 2008 and 2007:


	Three Months Ended June 30,				Six Months Ended June 30,
	2008		2007		2008		2007
	(in thousands, except per unit data)
Revenues	$	276,505	$	144,144	$	433,319	$	268,344
Expenses	$	232,176	$	116,762	$	357,756	$	218,622

Operating income	$	44,329	$	27,382	$	75,563	$	49,722
Net income	$	9,471	$	16,560	$	44,011	$	32,993
Net income per limited partner unit, basic and diluted	$	0.10	$	0.30	$	0.73	$	0.60
Cash flows provided by operating activities	$	44,481	$	33,798	$	73,327	$	57,316

Operating income increased by $16.9 million in the three months ended June 30, 2008 compared to the same period of 2007 primarily due to a $12.6 million increase in natural gas midstream gross margin and a $7.6 million increase in coal royalties revenues, partially offset by a $3.1 million increase in depreciation, depletion and amortization expense (“DD&A”). Operating income increased by $25.8 million in the six months ended June 30, 2008 compared to the same period of 2007 primarily due to a $22.4 million increase in natural gas midstream gross margin and a $6.6 million increase in coal royalties revenues, partially offset by a $4.5 million increase in DD&A.

Net income decreased by $7.1 million in the three months ended June 30, 2008 compared to the same period in 2007 primarily due to a $22.4 million increase in derivative expense partially offset by the $16.9 million increase in operating income. Net income increased by $11.0 million in the six months ended June 30, 2008 compared to the same period in 2007 primarily due to the $25.8 million increase in operating income, partially offset by a $12.0 million increase in derivative expense.

Coal and Natural Resource Management Segment

Three Months Ended June 30, 2008 Compared With the Three Months Ended June 30, 2007

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the three months ended June 30, 2008 and 2007:


	Three Months Ended June 30,						% Change
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	31,641		$	24,029		32	%
Coal services		1,841			2,092		(12	)%
Timber		1,833			238		670	%
Oil and gas royalty		1,556			306		408	%
Other		2,185			1,745		25	%

Total revenues		39,056			28,410		37	%


Expenses
Coal royalties expense		3,397			1,820		87	%
Other operating		505			694		(27	)%
Taxes other than income		371			267		39	%
General and administrative		3,274			2,743		19	%
Depreciation, depletion and amortization		7,526			5,320		41	%

Total expenses		15,073			10,844		39	%

Operating income	$	23,983		$	17,566		37	%


Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,839			8,060		10	%
Average royalties revenues per ton ($/ton)	$	3.58		$	2.98		20	%
Less royalties expense per ton ($/ton)		(0.38	)		(0.23	)	65	%

Average net coal royalties per ton ($/ton)	$	3.20		$	2.75		16	%

Revenues. Coal royalties revenues increased by $7.6 million, or 32%, from $24.0 million in the three months ended June 30, 2007 to $31.6 million in the same period of 2008. Coal royalties expense increased by $1.6 million, or 87%, from $1.8 million in the three months ended June 30, 2007 to $3.4 million in the same period of 2008 due primarily to the timing of longwall mining in Central Appalachia. Tons produced by our lessees increased by 0.7 million tons, or 10%, from 8.1 million tons in the three months ended June 30, 2007 to 8.8 million tons in the same period of 2008, which was due primarily to increases in production in the Illinois Basin. The increase in this region was due primarily to the June 2007 acquisition of lease rights to coal reserves in western Kentucky, where we first recorded production in August 2007.

Our average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.45 per ton, or 16%, from $2.75 per ton in the three months ended June 30, 2007 to $3.20 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to the increase in average royalty revenues per ton received in Central Appalachia, partially offset by lower royalty revenues per ton received from the aforementioned Illinois Basin acquisition. The increase in average royalty revenues per ton received in Central Appalachia was due primarily to higher coal prices for the region. The decrease in the Illinois Basin was due primarily to a lower royalty rate per ton on the newly acquired lease rights.

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the three months ended June 30, 2008 and 2007:


	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Three Months Ended June 30,		Three Months Ended June 30,						Three Months Ended June 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	5,144	5,018	$	24,450		$	18,274		$	4.75		$	3.64
Northern Appalachia	1,110	1,080		1,857			1,654			1.67			1.53
Illinois Basin	1,119	501		2,312			1,180			2.07			2.36
San Juan Basin	1,466	1,461		3,022			2,921			2.06			2.00

Total	8,839	8,060	$	31,641		$	24,029		$	3.58		$	2.98

Less coal royalties expense (1)				(3,397	)		(1,820	)		(0.38	)		(0.23	)

Net coal royalties revenues			$	28,244		$	22,209		$	3.20		$	2.75

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

Coal services revenues decreased by $0.3 million, or 12%, from $2.1 million in the three months ended June 30, 2007 to $1.8 million in the same period of 2008. This decrease is due primarily to the exhaustion of a fee related to a plant in West Virginia. Timber revenues increased by $1.6 million, or 670%, from $0.2 million in the three months ended June 30, 2007 to $1.8 million in the same period of 2008 primarily due to the effects of our September 2007 forestland acquisition. Oil and gas royalty revenues increased by $1.3 million, or 408%, from $0.3 million in the three months ended June 30, 2007 to $1.6 million in the same period of 2008 primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $0.5 million, or 25%, from $1.7 million in the three months ended June 30, 2007 to $2.2 million in the same period of 2008 primarily due to increased wheelage income in the Central Appalachian region related to an increase in sales prices.

Expenses. Other operating expenses decreased by $0.2 million, or 27%, from $0.7 million in the three months ended June 30, 2007 to $0.5 million in the same period of 2008 primarily due to the timing of core-drilling activities. Taxes other than income increased by $0.1 million, or 39%, from $0.3 million in the three months ended June 30, 2007 to $0.4 million in the same period of 2008 primarily due to an increase in severance taxes paid on sales related to our timber leases. General and administrative expenses increased by $0.6 million, or 19%, from $2.7 million in the three months ended June 30, 2007 to $3.3 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $2.2 million, or 41%, from $5.3 million in the three months ended June 30, 2007 to $7.5 million in the same period of 2008 primarily due to increased depletion resulting from our forestland acquisition in September 2007 and our oil and gas royalty interest acquisition in October 2007.

Six Months Ended June 30, 2008 Compared With the Six Months Ended June 30, 2007

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the six months ended June 30, 2008 and 2007:


	Six Months Ended June 30,						% Change
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	55,603		$	49,029		13	%
Coal services		3,703			3,693		0	%
Timber		3,417			417		719	%
Oil and gas royalty		2,790			583		379	%
Other		3,837			3,172		21	%

Total revenues		69,350			56,894		22	%


Expenses
Coal royalties expense		5,909			3,603		64	%
Other operating		736			1,066		(31	)%
Taxes other than income		742			590		26	%
General and administrative		6,459			5,359		21	%
Depreciation, depletion and amortization		13,939			10,810		29	%

Total expenses		27,785			21,428		30	%

Operating income	$	41,565		$	35,466		17	%

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		16,479			16,344		1	%
Average royalties revenues per ton ($/ton)	$	3.37		$	3.00		12	%
Less royalties expense per ton ($/ton)		(0.36	)		(0.22	)	64	%

Average net coal royalties per ton ($/ton)	$	3.01		$	2.78		8	%

Revenues. Coal royalties revenues increased by $6.6 million, or 13%, from $49.0 million in the six months ended June 30, 2007 to $55.6 million in the same period of 2008. Coal royalties expense increased by $2.3 million, or 64%, from $3.6 million in the six months ended June 30, 2007 to $5.9 million in the same period of 2008 due primarily to the timing of longwall mining in Central Appalachia. Total tons produced by our lessees remained relatively constant from the six months ended June 30, 2007 to the same period in 2008, due primarily to increased production in the Illinois Basin that was mostly offset by decreased production in Northern Appalachia. The increased production in the Illinois Basin was primarily due to the June 2007 acquisition of lease rights to coal reserves in western Kentucky, where we first recorded production in August 2007. The decreased production in Northern Appalachia was due to adverse conditions related to longwall production.

Our average net coal royalty per ton, which represents the average coal royalties revenue per ton, net of coal royalties expense, increased by $0.23 per ton, or 8%, from $2.78 per ton in the six months ended June 30, 2007 to $3.01 per ton in the same period of 2008. The increase in the average net coal royalty per ton was due primarily to an increase in average royalty revenues per ton received in Central Appalachia, partially offset by lower royalty revenues per ton received form the aforementioned Illinois Basin acquisition. The increase in average royalty revenues per ton received in Central Appalachia was due primarily to higher coal prices for the region. The decrease in the Illinois Basin was due primarily to a lower royalty rate per ton on the newly acquired lease rights.

The following table summarizes coal production, coal royalties revenues and coal royalties per ton by region for the six months ended June 30, 2008 and 2007:


	Coal Production		Coal Royalties Revenues						Coal Royalties Per Ton
	Six Months Ended June 30,		Six Months Ended June 30,						Six Months Ended June 30,
Property	2008	2007	2008			2007			2008			2007
	(tons in thousands)		(in thousands)						($/ton)
Central Appalachia	9,955	9,975	$	43,029		$	37,184		$	4.32		$	3.73
Northern Appalachia	1,784	2,450		2,991			3,757			1.68			1.53
Illinois Basin	2,152	1,120		4,250			2,487			1.97			2.22
San Juan Basin	2,588	2,799		5,333			5,601			2.06			2.00

Total	16,479	16,344	$	55,603		$	49,029		$	3.37		$	3.00

Less coal royalties expense (1)				(5,909	)		(3,603	)		(0.36	)		(0.22	)

Net coal royalties revenues			$	49,694		$	45,426		$	3.01		$	2.78

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

Coal services revenues remained relatively constant from the six months ended June 30, 2007 to the same period of 2008. Timber revenues increased by $3.0 million, or 719%, from $0.4 million in the six months ended June 30, 2007 to $3.4 million in the same period of 2008 primarily due to the effects of our September 2007 forestland acquisition. Oil and gas royalty revenues increased by $2.2 million, or 379%, from $0.6 million in the six months ended June 30, 2007 to $2.8 million in the same period of 2008 primarily due to the increased royalties resulting from our October 2007 oil and gas royalty interest acquisition. Other revenues, which consisted primarily of wheelage fees, forfeiture income and management fee income, increased by $0.6 million, or 21%, from $3.2 million in the six months ended June 30, 2007 to $3.8 million in the same period of 2008 primarily due to increased wheelage income in the Central Appalachian region related to an increase in sales prices.

Expenses. Other operating expenses decreased by $0.4 million, or 31%, from $1.1 million in the six months ended June 30, 2007 to $0.7 million in the same period of 2008 primarily due to the timing of core-drilling activities. Taxes other than income increased by $0.1 million, or 26%, from $0.6 million in the six months ended June 30, 2007 to $0.7 million in the same period of 2008 primarily due to an increase in severance taxes paid on sales related to our timber leases. General and administrative expenses increased by $1.1 million, or 21%, from $5.4 million in the six months ended June 30, 2007 to $6.5 million in the same period of 2008 primarily due to increased staffing costs. DD&A expenses increased by $3.1 million, or 29%, from $10.8 million in the six months ended June 30, 2007 to $13.9 million in the same period of 2008 primarily due to increased depletion resulting from our forestland acquisition in September 2007 and our oil and gas royalty interest acquisition in October 2007.

Natural Gas Midstream Segment

Three Months Ended June 30, 2008 Compared With the Three Months Ended June 30, 2007

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the three months ended June 30, 2008 and 2007:


	Three Months Ended June 30,						% Change
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	153,537		$	69,384		121	%
Natural gas liquids		70,507			41,162		71	%
Condensate		8,452			3,157		168	%
Gathering and transportation fees		2,301			704		227	%

Total natural gas midstream revenues (1)		234,797			114,407		105	%
Equity earnings in equity investment		556			—		—
Producer services		2,096			1,327		58	%

Total revenues		237,449			115,734		105	%


Expenses
Cost of midstream gas purchased (1)		202,819			95,077		113	%
Operating		4,817			2,983		61	%
Taxes other than income		605			336		80	%
General and administrative		3,469			3,020		15	%
Depreciation and amortization		5,393			4,502		20	%

Total operating expenses		217,103			105,918		105	%

Operating income	$	20,346		$	9,816		107	%


Operating Statistics
System throughput volumes (MMcf)		23,884			17,019		40	%
System throughput volumes (MMcf/day)		262			187		40	%

Gross margin	$	31,978		$	19,330		65	%
Impact of derivatives		(8,186	)		(904	)	806	%

Gross margin, adjusted for impact of derivatives	$	23,792		$	18,426		29	%


Gross margin ($/Mcf)	$	1.34		$	1.14		18	%
Impact of derivatives ($/Mcf)		(0.34	)		(0.05	)	580	%

Gross margin, adjusted for impact of derivatives ($/Mcf)	$	1.00		$	1.09		(8	)%

(1)

In the three months ended June 30, 2008, we recorded $49.8 million of natural gas midstream revenue and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from Penn Virginia Oil & Gas, L.P. (“PVOG”) and the subsequent sale of that gas 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.

Natural gas midstream revenues increased by $120.4 million, or 105%, from $114.4 million in the three months ended June 30, 2007 to $234.8 million in the same period of 2008. Cost of midstream gas purchased increased by $107.7 million, or 113%, from $95.1 million in the three months ended June 30, 2007 to $202.8 million in the same period of 2008. Our gross margin increased by $12.7 million, or 65%, from $19.3 million in the three months ended June 30, 2007 to $32.0 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volumes and higher fractionation, or “frac” spreads during the three months ended June 30, 2008 compared to the same period of 2007. 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 75 MMcfd, or 40%, from 187 MMcfd in the three months ended June 30, 2007 to 262 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in the second quarter of 2008. Also, the continued successful development by producers operating in the vicinity of our systems, as well as our success in contracting and connecting new supply contributed to the increase in throughput volume.

In the second quarter of 2008, our two expansion projects related to natural gas processing facilities were operational. These two natural gas processing facilities include the Spearman plant in the Texas Panhandle, which was placed into service in February 2008 and has approximately 60 MMcfd capacity, and the Crossroads plant in East Texas, which was placed in service in April 2008 and has approximately 80 MMcfd capacity. The Crossroads plant will process most of the Cotton Valley gas production for Penn Virginia, and the Spearman plant will process gas that had previously bypassed the Beaver plant.

During the three months ended June 30, 2008, we generated a majority of our gross margin from contractual arrangements under which our 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. Adjusted for the impact of derivative financial instruments, our gross margin increased by $5.4 million, or 29%, from $18.4 million for the three months ended June 30, 2007 to $23.8 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives decreased by $0.09, or 8%, from $1.09 per Mcf in the three months ended June 30, 2007 to $1.00 per Mcf in the same period of 2008. The decrease in gross margin on a per Mcf basis was due to an increase in fee-based volumes associated with the Crossroads plant.

Producer Services. Producer services revenues increased by $0.8 million, or 58%, from $1.3 million in the three months ended June 30, 2007 to $2.1 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production.

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 the second quarter of 2008.

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

Operating expenses increased by $1.8 million, or 61%, from $3.0 million in the three months ended June 30, 2007 to $4.8 million in the same period of 2008 primarily due to expenses related to our expanding footprint in areas of operation, including the addition of the Spearman and Crossroads plants. Taxes other than income increased by $0.3 million, or 80%, from $0.3 million in the three months ended June 30, 2007 to $0.6 million in the same period of 2008 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $0.5 million, or 15%, from $3.0 million in the three months ended June 30, 2007 to $3.5 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $0.9 million, or 20%, from $4.5 million in the three months ended June 30, 2007 to $5.4 million in the same period of 2008. This increase is primarily due to expansion capital incurred, which includes the Spearman and Crossroads plants.

Six Months Ended June 30, 2008 Compared With the Six Months Ended June 30, 2007

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the six months ended June 30, 2008 and 2007:


	Six Months Ended June 30,						% Change
	2008			2007			% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Residue gas	$	215,204		$	129,064		67%
Natural gas liquids		126,704			73,150		73%
Condensate		14,668			6,073		142%
Gathering and transportation fees		3,269			1,438		127%

Total natural gas midstream revenues (1)		359,845			209,725		72%
Equity earnings in equity investment		556			—		—
Producer services		3,568			1,725		107%

Total revenues		363,969			211,450		72%


Expenses
Cost of midstream gas purchased (1)		302,516			174,808		73%
Operating		8,867			6,342		40%
Taxes other than income		1,306			856		53%
General and administrative		6,802			6,043		13%
Depreciation and amortization		10,480			9,145		15%

Total operating expenses		329,971			197,194		67%

Operating income	$	33,998		$	14,256		138%


Operating Statistics
System throughput volumes (MMcf)		41,171			32,919		25%
System throughput volumes (MMcf/day)		226			182		24%

Gross margin	$	57,329		$	34,917		64%
Impact of derivatives		(16,600	)		(2,133	)	678%

Gross margin, adjusted for impact of derivatives	$	40,729		$	32,784		24%


Gross margin ($/Mcf)	$	1.39		$	1.06		31%
Impact of derivatives ($/Mcf)		(0.40	)		(0.07	)	471%

Gross margin, adjusted for impact of derivatives ($/Mcf)	$	0.99		$	0.99		—

(1)

In the six months ended June 30, 2008, we recorded $49.8 million of natural gas midstream revenue and $49.8 million for the cost of midstream gas purchased related to the purchase of natural gas from PVOG and the subsequent sale of that gas to third parties. These transactions do not impact the gross margin.

Gross Margin. Natural gas midstream revenues increased by $150.1 million, or 72%, from $209.7 million in the six months ended June 30, 2007 to $359.8 million in the same period of 2008. Cost of midstream gas purchased increased by $127.7 million, or 73%, from $174.8 million in the six months ended June 30, 2007 to $302.5 million in the same period of 2008. Our gross margin increased by $22.4 million, or 64%, from $34.9 million in the six months ended June 30, 2007 to $57.3 million in the same period of 2008. The gross margin increase was a result of increased commodity pricing, increased system throughput volumes and higher fractionation, or “frac” spreads during the six months ended June 30, 2008 compared to the same period of 2007. 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 44 MMcfd, or 24%, from 182 MMcfd in the six months ended June 30, 2007 to 226 MMcfd in the same period of 2008. This increase in throughput volumes is due primarily to the Crossroads plant in East Texas, which became fully operational in the second quarter of 2008. Also, the continued successful development by producers operating in the vicinity of our systems, as well as our success in contracting and connecting new supply contributed to the increase in throughput volume.

In the second quarter of 2008, our two expansion projects related to natural gas processing facilities were operational. These two natural gas processing facilities included the Spearman plant in the Texas Panhandle, which was placed into service in February 2008 and has approximately 60 MMcfd capacity and the Crossroads plant in East Texas, which was placed in service in April 2008 and has approximately 80 MMcfd capacity. The Crossroads plant will process most of the Cotton Valley gas production for Penn Virginia, and the Spearman plant will process gas that had previously bypassed the Beaver plant.

During the six months ended June 30, 2008, we generated a majority of our gross margin from contractual arrangements under which our 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. Adjusted for the impact of derivative financial instruments, our gross margin increased by $7.9 million, or 24%, from $32.8 million for the six months ended June 30, 2007 to $40.7 million for the same period of 2008. On a per Mcf basis, the gross margin adjusted for the impact of derivatives remained relatively constant in the six months ended June 30, 2007 to the same period of 2008.

Producer Services. Producer services revenues increased by $1.9 million, or 107%, from $1.7 million in the six months ended June 30, 2007 to $3.6 million in the same period of 2008 primarily due to an increase in collected agent fees for the marketing of Penn Virginia’s and other third parties’ natural gas production.

Operating expenses increased by $2.6 million, or 40%, from $6.3 million in the six months ended June 30, 2007 to $8.9 million in the same period of 2008 primarily due to expenses related to our expanding footprint in areas of operation, including the addition of the Spearman and Crossroads plants. Taxes other than income increased by $0.4 million, or 53%, from $0.9 million in the six months ended June 30, 2007 to $1.3 million in the same period of 2008 primarily due to increased property taxes resulting from the construction of the Spearman and Crossroads plants. General and administrative expenses increased by $0.8 million, or 13%, from $6.0 million in the six months ended June 30, 2007 to $6.8 million in the same period of 2008 primarily due to increased staffing costs. Depreciation and amortization expenses increased by $1.4 million, or 15%, from $9.1 million in the six months ended June 30, 2007 to $10.5 million in the same period of 2008. This increase is primarily due to expansion capital incurred, which includes the Spearman and Crossroads plants.

Other

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

Interest Expense. Interest expense increased by $1.8 million, or 49%, from $3.6 million in the three months ended June 30, 2007 to $5.4 million in the same period of 2008. This increase is primarily due to the increase in our average debt balance, which increased from $241.6 million for the three months ended June 30, 2007 to $411.8 million for the same period of 2008. The increase in our average debt balance is due primarily to acquisitions and expansion activity. We also capitalized $0.2 million of interest costs in the three months ended June 30, 2008 related to the construction of the Spearman and Crossroads plants. We had no capitalized interest in the three months ended June 30, 2007.

Interest expense increased by $3.1 million, or 44%, from $7.2 million in the six months ended June 30, 2007 to $10.3 million in the same period of 2008. This increase is primarily due to the increase in our average debt balance, which increased from $232.9 million for the six months ended June 30, 2007 to $411.9 million for the same period of 2008. The increase in our average debt balance is due primarily to acquisitions and expansion activity. We also capitalized $0.7 million of interest costs in the six months ended June 30, 2008 related to the construction of the Spearman and Crossroads plants. We had no capitalized interest in the six months ended June 30, 2007.

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.

Commodity prices increased substantially in the second quarter of 2008, resulting in derivative expenses of $29.9 million for changes in fair value. Cash paid for settlements totaled $9.7 million for the three months ended June 30, 2008. The derivative expenses in the three months ended June 30, 2007 were $7.6 million for changes in fair value. Cash paid for settlements totaled $2.2 million for the three months ended June 30, 2007.

Primarily due to the increase in commodity prices in the six months ended June 30, 2008, derivative expenses were $22.2 million for changes in fair value. Cash paid for settlements totaled $19.2 million for the six months ended June 30, 2008. The derivative expenses in the six months ended June 30, 2007 were $10.2 million for changes in fair value. Cash paid for settlements totaled $4.3 million in the six months ended June 30, 2007.

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.

Natural Gas Midstream Revenues

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. 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 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 have historically not been significant, between the actual amounts ultimately received or paid and the original estimates in the period they become finalized.

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.

Derivative Activities

Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we recognized the deferred changes in fair value in revenues and cost of gas purchased in our condensed consolidated statements of income. As of June 30, 2008, we had $2.9 million of net losses remaining in accumulated other comprehensive income. We will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). Because we no longer use hedge accounting for our commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of these contracts. Our results of operations are affected by the potential volatility of changes in fair value, which fluctuate with changes in NGL, crude oil and natural gas prices. These fluctuations could be significant in a volatile pricing environment.

Depletion

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 coal reserve engineers. Our estimates of coal reserves are updated periodically and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. We deplete timber on an area-by-area basis at a rate based upon the quantity of timber sold. 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.

Equity Investments

We use the equity method of accounting to account for our 25% member interest in Thunder Creek, as well as our investment in a coal handling joint venture, recording the initial investment at cost. Subsequently, the carrying amount of the investment is increased to reflect our share of income of the investee and is reduced to reflect our share of losses of the investee or distributions received from the investee as the joint ventures reports them. Our share of earnings or losses from Thunder Creek is included in other revenues on the condensed consolidated statements of income, and our share of earnings and losses from the coal handling joint venture is included in coal services on the condensed consolidated statements of income. Other revenues and coal services revenues also include amortization of the amount of the equity investments that exceed our portion of the underlying equity in net assets. We record amortization over the life of the contracts acquired in the Thunder Creek acquisition and the life of the coal services contracts acquired in acquisition of the aforementioned coal handling joint venture.

Goodwill

Under SFAS No. 141, Business Combinations, and SFAS No. 142 goodwill recorded in connection with a business combination is not amortized, but tested for impairment at least annually. Accordingly, we do not amortize goodwill. We test goodwill for impairment during the fourth quarter of each fiscal year.

Intangible Assets

Intangible assets are primarily associated with assumed contracts, customer relationships and rights-of-way. These intangible assets are amortized over periods of up to 15 years, the period in which benefits are derived from the contracts, relationships and rights-of-way, 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, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being 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. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157, delays the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008.

SFAS No. 157 requires fair value measurements to be classified and disclosed in one of the following three categories:

•

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).

We use the following methods and assumptions to estimate the fair values of financial instruments:

•

Commodity derivative instruments: The fair values of our derivative agreements are determined based on forward price quotes 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. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 6 – Derivative Instruments in Item 1, “Financial Statements,” of the Condensed Consolidated Financial Statements.

•

Interest rate swaps: We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. 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. The discount rates used in the discounted cash flow projections include a measure of nonperformance risk. See Note 6 – Derivative Instruments in Item 1, “Financial Statements,” of the Condensed Consolidated Financial Statements.

Environmental Matters

Recent Accounting Pronouncements

See Note 2 – Summary of Significant Accounting Policies, in Item 1, “Financial Statements,” of the 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;

•

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 market) and political conditions (including the impact of potential terrorist attacks); and

•

other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2007.

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, 2007. Many of the factors that will determine our future results are beyond the ability of management to control or predict. Readers should not place undue reliance on forward-looking statements, which reflect management’s views only as of the date hereof. We undertake no obligation to revise or update any forward-looking statements, or to make any other forward-looking statements, whether as a result of new information, future events or otherwise.

Item 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 natural gas, NGL, crude oil and coal price risks and interest rate risk.

We are also indirectly exposed to the credit risk of our customers and lessees. If our customers or lessees become financially insolvent, they may not be able to continue to operate or meet their payment obligations.

Price Risk Management

Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to seek to mitigate the price risks associated with fluctuations in natural gas, NGL and crude oil prices as they relate to our natural gas midstream business. The derivative financial instruments are placed with major financial institutions that we believe are of minimum 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.

For the six months ended June 30, 2008, we reported a net derivative expense of $22.2 million. Until 2006, we used hedge accounting for commodity derivative financial instruments as allowed under SFAS No. 133. Our commodity derivative financial instruments initially qualified as cash flow hedges, and changes in fair value from these contracts were deferred in accumulated comprehensive income until the hedged transactions settled. When we discontinued hedge accounting in 2006, a net loss remained in accumulated other comprehensive income. As the hedged transactions settled in 2006 and 2007, we recognized the deferred changes in fair value in revenues and cost of gas purchased in our condensed consolidated statements of income. As of June 30, 2008, we had $2.9 million of net losses remaining in accumulated other comprehensive income. We will recognize these hedging losses during the remainder of 2008 as the hedged transactions settle.

Beginning in 2006, we began recognizing changes in fair value in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). Because we no longer use hedge accounting for our commodity derivatives, we have experienced and could continue to experience significant changes in the estimate of derivative gains or losses recognized due to fluctuations in the value of these contracts. Our results of operations are affected by the potential volatility of changes in fair value, which fluctuate with changes in natural gas, NGL and crude oil prices. These fluctuations could be significant in a volatile pricing environment.

The following table lists our derivative agreements and their fair values as of June 30, 2008 (in thousands):


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars						Estimated Fair Value
	Average Volume Per Day		Weighted Average Price			Additional Put Option		Put		Call		Estimated Fair Value
Frac Spread	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	7,824		$	5.02								$	(5,944	)
Ethane Sale Swap	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	34,440		$	0.4700									(4,774	)
Propane Sale Swaps	(in gallons	)		(per gallon	)
Third Quarter 2008 through Fourth Quarter 2008	26,040		$	0.7175									(5,675	)
Crude Oil Sale Swaps	(in barrels	)		(per barrel	)
Third Quarter 2008 through Fourth Quarter 2008	560		$	49.27									(9,334	)
Natural Gasoline Collar	(in gallons	)							(per gallon)
Third Quarter 2008 through Fourth Quarter 2008	6,300							$	1.4800	$	1.6465		(1,611	)
Crude Oil Collar	(in barrels	)							(per barrel)
Third Quarter 2008 through Fourth Quarter 2008	400							$	65.00	$	75.25		(4,784	)
Natural Gas Sale Swaps	(in MMBtu	)		(per MMBtu	)
Third Quarter 2008 through Fourth Quarter 2008	4,000		$	6.97									4,795
Crude Oil Three-Way Collar	(in barrels	)							(per gallon)
First Quarter 2009 through Fourth Quarter 2009	1,000					$	70.00	$	90.00	$	119.25		(10,292	)
Frac Spread Collar (1)	(in MMBtu	)							(in MMBtu)
First Quarter 2009 through Fourth Quarter 2009	6,000							$	9.09	$	13.94		—
Settlements to be paid in subsequent period													(5,246	)

Natural gas midstream segment commodity derivatives—net liability												$	(42,865	)

(1)	We entered into this contract in July 2008.

Our management estimates that excluding the derivative positions described above, for every $1.00 per MMBtu decrease or increase in natural gas prices, natural gas midstream gross margin and operating income for the last six months of 2008 would increase or decrease by approximately $5.6 million. In addition, our management estimates that for every $5.00 per barrel increase or decrease in the oil prices, natural gas midstream gross margin and operating income would increase or decrease by approximately $2.3 million. This assumes that crude oil, natural gas prices and inlet volumes remain constant at forecasted levels. These estimated changes in gross margin and operating income exclude the potential cash receipts or payments in settling these derivative positions.

Interest Rate Risk

As of June 30, 2008, we had $323.1 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps to effectively convert the interest rate on $160.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.33% plus the applicable margin until March 2010. From March 2010 to December 2011, the Revolver Swaps will effectively convert the interest rate on $100.0 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.40% plus the applicable margin. The Revolver Swaps are accounted for as cash flow hedges in accordance with SFAS No. 133. A 1% increase in short-term interest rates on the floating rate debt outstanding under the Revolver (net of amounts fixed through hedging transactions) at June 30, 2008 would cost us approximately $1.6 million in additional interest expense.

Item 4

Controls and Procedures

(a) Disclosure Controls and Procedures

Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we performed an evaluation of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) as of June 30, 2008. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of June 30, 2008, 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.

PART II. OTHER INFORMATION

Item 6

Exhibits


10.1		Purchase and Sale Agreement dated June 17, 2008 between Lone Star Gathering, L.P. and Penn Virginia Resource Partners, L.P., as amended by First Amendment to Purchase and Sale Agreement dated as of July 17, 2008 (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on July 22, 2008).

10.2		Units Purchase Agreement dated June 17, 2008 by and among Penn Virginia Resource LP Corp., Kanawha Rail Corp. and Penn Virginia Resource Partners, L.P. (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on July 22, 2008).

12.1		Statement of Computation of Ratio of Earnings to Fixed Charges Calculation.

31.1		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification Pursuant to Exchange Act Rule 13a-14(a) or Rule 15d-14(a), as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

SIGNATURES

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


		PENN VIRGINIA RESOURCE PARTNERS, L.P.

		By: PENN VIRGINIA RESOURCE GP, LLC

Date: August 7, 2008	By:	/s/ Frank A. Pici
		Frank A. Pici
		Vice President and Chief Financial Officer

Date: August 7, 2008	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

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