PVR Partners, L. P. 10Q 2007 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2007

¨	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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer x Non-accelerated filer ¨

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 November 1, 2007, 46,106,285 common units representing limited partner interests of the registrant were outstanding.

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

INDEX


		Page
PART I.	Financial Information

Item 1.	Financial Statements

	Condensed Consolidated Statements of Income for the Three Months and Nine Months Ended September 30, 2007 and 2006	1

	Condensed Consolidated Balance Sheets as of September 30, 2007 and December 31, 2006	2

	Condensed Consolidated Statements of Cash Flows for the Three Months and Nine Months Ended September 30, 2007 and 2006	3

	Notes to Condensed Consolidated Financial Statements	4

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31

Item 4.	Controls and Procedures	33

PART II.	Other Information

Item 6.	Exhibits	34

PART I. FINANCIAL INFORMATION

Item 1

Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Revenues
Natural gas midstream	$	100,370		$	100,809		$	310,095		$	305,340
Coal royalties		24,426			26,612			73,455			73,288
Coal services		1,955			1,515			5,648			4,345
Other		3,453			2,558			9,350			7,148

Total revenues		130,204			131,494			398,548			390,121

Expenses
Cost of midstream gas purchased		76,192			80,272			251,000			254,615
Operating		5,224			6,378			16,235			13,950
Taxes other than income		666			483			2,112			1,619
General and administrative		5,706			4,599			17,108			15,003
Depreciation, depletion and amortization		10,645			9,864			30,600			27,501

Total expenses		98,433			101,596			317,055			312,688

Operating income		31,771			29,898			81,493			77,433
Other income (expense)
Interest expense		(4,678	)		(5,276	)		(11,842	)		(13,759	)
Interest income and other		299			331			931			902
Derivatives		(10,730	)		6,386			(20,927	)		(11,676	)

Net income	$	16,662		$	31,339		$	49,655		$	52,900

General partner’s interest in net income	$	3,385		$	1,583		$	8,819		$	2,995

Limited partners’ interest in net income	$	13,277		$	29,756		$	40,836		$	49,905

Basic and diluted net income per limited partner unit (see note 5)	$	0.29		$	0.55		$	0.89		$	1.15

Weighted average number of units outstanding, basic and diluted:
Common		46,106			33,994			44,084			33,994
Class B		—			—			2,019			—
Subordinated		—			7,650			—			7,650

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)


	September 30,			December 31,
	2007			2006
	(unaudited)
Assets
Current assets
Cash and cash equivalents	$	3,446		$	11,440
Accounts receivable		67,484			66,987
Derivative assets		1,231			449
Other current assets		2,299			2,587

Total current assets		74,460			81,463

Property, plant and equipment		826,808			665,135
Accumulated depreciation, depletion and amortization		(135,997	)		(108,622	)

Net property, plant and equipment		690,811			556,513

Derivative assets		802			2,455
Other long-term assets		82,865			73,592

Total assets	$	848,938		$	714,023

Liabilities and Partners’ Capital
Current liabilities
Accounts payable and accrued liabilities	$	57,064		$	63,253
Current portion of long-term debt		12,554			10,832
Deferred income		5,761			6,999
Derivative liabilities		22,115			6,996

Total current liabilities		97,494			88,080
Deferred income		3,649			6,592
Other liabilities		3,312			3,339
Derivative liabilities		3,457			6,618
Long-term debt		351,618			207,214
Partners’ capital		389,408			402,180

Total liabilities and partners’ capital	$	848,938		$	714,023

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

PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Cash flows from operating activities
Net income	$	16,662		$	31,339		$	49,655		$	52,900
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		10,645			9,864			30,600			27,501
Commodity derivative contracts:
Total derivative losses		12,034			(5,561	)		24,359			12,951
Cash settlements of derivatives		(4,702	)		(7,344	)		(8,963	)		(15,405	)
Non-cash interest expense		164			191			494			573
Equity earnings, net of distributions received		(255	)		(425	)		(1,133	)		1,603
Changes in operating assets and liabilities		(5,528	)		(3,159	)		(8,676	)		(4,699	)

Net cash provided by operating activities		29,020			24,905			86,336			75,424

Cash flows from investing activities
Acquisitions		(93,423	)		(199	)		(145,879	)		(81,586	)
Additions to property, plant and equipment		(10,781	)		(11,572	)		(29,655	)		(26,893	)
Other		—			30			197			33

Net cash used in investing activities		(104,204	)		(11,741	)		(175,337	)		(108,446	)

Cash flows from financing activities
Distributions to partners		(22,873	)		(16,912	)		(65,853	)		(47,960	)
Proceeds from borrowings, net		89,000			10,000			146,000			71,500
Proceeds from issuance of units		—			—			860			—

Net cash provided by (used in) financing activities		66,127			(6,912	)		81,007			23,540

Net increase (decrease) in cash and cash equivalents		(9,057	)		6,252			(7,994	)		(9,482	)
Cash and cash equivalents – beginning of period		12,503			7,459			11,440			23,193

Cash and cash equivalents – end of period	$	3,446		$	13,711		$	3,446		$	13,711

Supplemental disclosure:
Cash paid for interest	$	6,642		$	5,621		$	13,545		$	14,484

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

September 30, 2007

1.	Organization

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “us” or “our”) is a Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 primarily to engage in the business of managing coal properties 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 providing fee-based coal preparation and transportation services to our lessees, which enhance their production levels and generate additional coal royalties revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through our joint venture with Massey Energy Company. In addition, we earn revenues from oil and gas royalty interests we own, from coal transportation, or wheelage, rights and from the sale of standing timber on our properties.

Our natural gas midstream segment is engaged in providing gas processing, gathering and other related natural gas services. We own and operate natural gas midstream assets located in Oklahoma and the panhandle of Texas. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. 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”). Penn Virginia owns an approximately 82% limited partner interest in PVG as well as the non-economic general partner interest in PVG. PVG owns an approximately 42% limited partner interest in us as well as the 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, 2006. 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 its 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 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. Our condensed consolidated financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2006. Operating results for the three months and nine months ended September 30, 2007 are not necessarily indicative of the results that may be expected for the year ending December 31, 2007. Certain reclassifications have been made to conform to the current period’s presentation.

New Accounting Standards

In September 2006, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 157,Fair Value Measurements, a standard that provides enhanced guidance for using fair value to measure assets and liabilities. SFAS No. 157 also responds to investors’ requests for expanded information about the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value and the effect of fair value measurements on earnings. SFAS No. 157 applies whenever other standards require (or permit) assets or liabilities to be measured at fair value. SFAS No. 157 does not expand the use of fair value in any new circumstances. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop fair value assumptions. SFAS No. 157 is effective for fiscal years and interim periods beginning after November 15, 2007. We are currently assessing the impact on our condensed consolidated financial statements of adopting SFAS No. 157 effective January 1, 2008.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities—Including an amendment of FASB Statement No. 115, which provides companies with an option to report selected financial assets and liabilities at fair value. The objective of SFAS No. 159 is to reduce both complexity in accounting for financial instruments and the volatility in earnings caused by measuring related assets and liabilities differently. SFAS No. 159 also establishes presentation and disclosure requirements designed to facilitate comparisons between companies that choose different measurement attributes for similar types of assets and liabilities. SFAS No. 159 is effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We are currently assessing the impact on our condensed consolidated financial statements of adopting SFAS No. 159 effective January 1, 2008.

3.	Acquisitions

In June 2007, we acquired fee ownership of approximately nine million tons of coal reserves. The reserves are located on approximately 1,700 acres in Jackson County, Illinois. The purchase price was $9.9 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of property, plant and equipment.

In June 2007, we acquired a combination of fee ownership and lease rights to approximately 51 million tons of coal reserves, along with a preparation plant and coal handling facilities. This property is located on approximately 17,000 acres in Webster and Hopkins Counties, Kentucky. The purchase price was $42.0 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of property, plant and equipment and other long-term assets. Approximately $30.0 million of the purchase price was allocated to the coal reserves, approximately $11.5 million was allocated to other long-term assets and approximately $0.5 million was allocated to plant property.

In September 2007, we acquired fee ownership of approximately 62,000 acres of forestland in Barbour, Randolph, Tucker and Upshur Counties, West Virginia. The purchase price was $93.1 million in cash and was funded with long-term debt under our revolving credit facility. The acquisition has been recorded as a component of property, plant and equipment.

4.	Derivative Instruments

Natural Gas Midstream Segment Commodity Derivatives

We utilize swap derivative contracts and costless collars to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of midstream gas purchased. 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 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. 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 (put) 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 (call) price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract.

The fair values of our derivative agreements are determined based on forward price quotes for the respective commodities as of September 30, 2007. The following table sets forth our positions as of September 30, 2007 for commodities related to natural gas midstream revenues (ethane, propane, natural gasoline and crude oil) and cost of midstream gas purchased (natural gas and crude oil):


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars				Estimated Fair Value
	Average Volume Per Day		Weighted Average Price			Put		Call		Estimated Fair Value
										(in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Fourth quarter 2007	34,440		$	0.5050						$	(1,240	)
First quarter 2008 through fourth quarter 2008	34,440		$	0.4700							(3,299	)
Propane Swaps	(in gallons	)		(per gallon	)
Fourth quarter 2007	26,040		$	0.7550							(1,384	)
First quarter 2008 through fourth quarter 2008	26,040		$	0.7175							(4,592	)
Crude Oil Swaps	(in barrels	)		(per barrel	)
Fourth quarter 2007	560		$	50.80							(1,502	)
First quarter 2008 through fourth quarter 2008	560		$	49.27							(5,355	)
Natural Gas Swaps (Purchase)	(in MMbtu	)		(per MMbtu	)
Fourth quarter 2007 through fourth quarter 2008	4,000		$	6.97							1,405
Natural Gasoline Swap/Crude Oil Swap (purchase)	(in gallons / in barrels	)		(per gallon / per barrel	)
Fourth quarter 2007	23,520 / 560			1.265 / 57.12							33
Ethane Collar	(in gallons	)					(per gallon)
Fourth quarter 2007	5,000					$	0.6100	$	0.7125		(88	)
Propane Collar	(in gallons	)					(per gallon)
Fourth quarter 2007	9,000					$	1.0300	$	1.1640		(148	)
Natural Gasoline Collar	(in gallons	)					(per gallon)
Fourth quarter 2007 through fourth quarter 2008	6,300					$	1.4800	$	1.6465		(366	)
Crude Oil Collar	(in barrels	)					(per barrel)
First quarter 2008 through fourth quarter 2008	400					$	65.00	$	75.25		(600	)
Frac Spread	(in MMbtu	)		(per MMbtu	)
Fourth quarter 2007	7,128		$	4.55							(2,601	)
First quarter 2008 through fourth quarter 2008	4,193		$	4.30							(1,933	)
Settlements to be paid in subsequent period											(2,428	)

Natural gas midstream segment commodity derivatives - net liability										$	(24,098	)

At September 30, 2007, we reported (i) a net derivative liability related to the natural gas midstream segment of $24.1 million and (ii) a loss in accumulated other comprehensive income of $6.6 million related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006. The $6.6 million loss will be recorded in earnings through the end of 2008 as the hedged transactions settle. The following table summarizes the effects of commodity derivative activities on our condensed consolidated statements of income:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Income statement caption:
Natural gas midstream revenues	$	(2,077	)	$	(2,724	)	$	(6,413	)	$	(7,456	)
Cost of midstream gas purchased		773			1,899			2,981			6,181
Derivatives		(10,730	)		6,386			(20,927	)		(11,676	)

Increase (decrease) in net income	$	(12,034	)	$	5,561		$	(24,359	)	$	(12,951	)

Realized and unrealized derivative impact:
Cash paid for derivative settlements	$	(4,702	)	$	(7,344	)	$	(8,963	)	$	(15,405	)
Unrealized derivative gain (loss)		(7,332	)		12,905			(15,396	)		2,454

Increase (decrease) in net income	$	(12,034	)	$	5,561		$	(24,359	)	$	(12,951	)

Interest Rate Swaps

In September 2005, we entered into interest rate swap agreements (the “Revolver Swaps”) to establish fixed rates on $60 million of the portion of the outstanding balance on our revolving credit facility that is based on the London Inter Bank Offering Rate (“LIBOR”) until March 2010. We pay a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were 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 expense. We reported (i) a derivative asset of approximately $0.6 million at September 30, 2007 and (ii) a gain in accumulated other comprehensive income of $0.6 million at September 30, 2007 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.5 million in net hedging gains in interest expense for the nine months ended September 30, 2007.

5.	Partners’ Capital and Distributions

As of September 30, 2007, partners’ capital consisted of 46.1 million common units, representing a 98% limited partner interest, and a 2% general partner interest. As of September 30, 2007, affiliates of Penn Virginia owned, in the aggregate, an approximately 42% limited partner interest in us, consisting of 19.8 million common units, and a 2% general partner interest in us.

Net Income per Limited Partner Unit

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. Emerging Issues Task Force (“EITF”) Issue No. 03-6,Participating Securities and the Two-Class Method under FASB Statement No. 128, 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 Issue No. 03-6 provides that in any accounting period where our net income exceeds our distribution for such period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. We make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. EITF Issue No. 03-6 does not impact our actual distributions for any period, but it can have the impact of reducing our earnings per limited partner unit. This result occurs as a larger portion of our earnings is allocated to the incentive distribution rights held by our general partner. In accounting periods where our net income does not exceed our distributions for such period, EITF Issue No.03-6 does not have any impact on our earnings per unit calculation. A reconciliation of net income and weighted

average units used in computing basic and diluted net income per limited partner unit for the three and nine months ended September 30, 2007 and 2006 is as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands, except per unit data)						(in thousands, except per unit data)
Net income	$	16,662		$	31,339		$	49,655		$	52,900
Less: General partner’s incentive distributions paid		(3,114	)		(976	)		(7,986	)		(2,277	)

Subtotal		13,548			30,363			41,669			50,623
General partner interest in net income		(271	)		(607	)		(833	)		(718	)

Limited partners’ interest in net income		13,277			29,756			40,836			49,905
Additional earnings allocation to general partner under EITF 03-6		—			(6,926	)		—			(1,973	)

Net income available to limited partner sunder EITF 03-6	$	13,277		$	22,830		$	40,836		$	47,932

Weighted average limited partner units, basic and diluted		46,106			41,644			46,103			41,644
Basic and diluted net income per limited partner unit	$	0.29		$	0.55		$	0.89		$	1.15

Cash Distributions

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 established by our general partner at its sole discretion. According to our partnership agreement, the 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	%

We are currently in the highest threshold of the incremental incentive cash distributions table above. The following table reflects the allocation of total cash distributions paid during the three months and nine months ended September 30, 2007 and 2006:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands)				(in thousands)
Limited partner units	$	19,364	$	15,617	$	56,710	$	44,769
General partner interest (2%)		395		319		1,157		914
Incentive distribution rights		3,114		976		7,986		2,277

Total cash distributions paid	$	22,873	$	16,912	$	65,853	$	47,960

We paid quarterly distributions of $0.40 per unit in February 2007, $0.41 per unit in May 2007 and $0.42 per unit in August 2007. In October 2007, we announced a $0.43 per unit distribution for the three months ended September 30, 2007, or $1.72 per unit on an annualized basis. The distribution will be paid on November 14, 2007 to unitholders of record at the close of business on November 5, 2007.

6.	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 totaled $1.4 million and $1.1 million in the three months ended September 30, 2007 and 2006 and $4.0 million and $3.7 million in the nine months ended September 30, 2007 and 2006. 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 $2.5 million as of September 30, 2007. This balance consists primarily of amounts due to Penn Virginia for general and administrative expenses incurred on our behalf and is included in accounts payable on our condensed consolidated balance sheets.

Marketing Revenues

Connect Energy Services, LLC, a wholly-owned subsidiary of ours, earned $0.4 million and $1.4 million in fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during the three months and nine months ended September 30, 2007. The marketing agreement was effective September 1, 2006. Penn Virginia Oil & Gas, L.P. is a wholly-owned subsidiary of Penn Virginia. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

7.	Long-Term Incentive Plan

We recognized compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under our general partner’s long-term incentive plan to employees of Penn Virginia who perform services for us. For the three months ended September 30, 2007 and 2006, we recognized a total of $0.7 million and $0.6 million of compensation expense related to the long-term incentive plan. For the nine months ended September 30, 2007 and 2006, we recognized a total of $1.8 million and $1.6 million of compensation expense related to the long-term incentive plan.

During the nine months ended September 30, 2007, 85,233 restricted units with a weighted average grant date fair value of $26.85 per unit were granted to employees of Penn Virginia who perform services for us. During the same period, 42,582 restricted units with a weighted average grant date fair value of $27.56 per unit vested. Restricted units granted in 2007 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.

8.	Comprehensive Income

Comprehensive income represents certain changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. For the three months and nine months ended September 30, 2007 and 2006, the components of comprehensive income were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
	(in thousands)						(in thousands)
Net income	$	16,662		$	31,339		$	49,655		$	52,900
Unrealized holding losses on derivative activities		(917	)		(1,059	)		(346	)		(5,844	)
Reclassification adjustment for derivative activities		1,129			645			2,913			1,409

Comprehensive income	$	16,874		$	30,925		$	52,222		$	48,465

9.	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 for all environmental and reclamation liabilities arising under those laws and regulations on the relevant lessees. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties under lease 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 September 30, 2007, our environmental liabilities included $1.5 million, which represents our best estimate of our liabilities as of that date 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 coal 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.

10.

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 chief operating 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; and collection of oil and gas royalties.

•

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

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


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Three Months Ended September 30, 2007:
Revenues	$	28,416	$	101,788	$	130,204
Cost of midstream gas purchased		—		76,192		76,192
Operating costs and expenses		4,871		6,725		11,596
Depreciation, depletion and amortization		5,833		4,812		10,645

Operating income	$	17,712	$	14,059		31,771

Interest expense, net						(4,379	)
Derivatives						(10,730	)

Net income					$	16,662

Total assets	$	561,169	$	287,769	$	848,938

Additions to property and equipment and acquisitions	$	93,449	$	10,755	$	104,204

For the Three Months Ended September 30, 2006:
Revenues	$	29,890	$	101,604	$	131,494
Cost of midstream gas purchased		—		80,272	$	80,272
Operating costs and expenses		5,589		5,871	$	11,460
Depreciation, depletion and amortization		5,551		4,313		9,864

Operating income	$	18,750	$	11,148	$	29,898

Interest expense, net						(4,945	)
Derivatives						6,386

Net income					$	31,339

Total assets	$	418,201	$	287,041	$	705,242

Additions to property and equipment and acquisitions	$	5,735	$	6,036	$	11,771


	Coal and Natural Resource Management		Natural Gas Midstream		Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2007:
Revenues	$	85,310	$	313,238	$	398,548
Cost of midstream gas purchased		—		251,000		251,000
Operating costs and expenses		15,489		19,966		35,455
Depreciation, depletion and amortization		16,643		13,957		30,600

Operating income	$	53,178	$	28,315		81,493

Interest expense, net						(10,911	)
Derivatives						(20,927	)

Net income					$	49,655

Total assets	$	561,169	$	287,769	$	848,938

Additions to property and equipment and acquisitions	$	146,915	$	28,619	$	175,534

For the Nine Months Ended September 30, 2006:
Revenues	$	83,115	$	307,006	$	390,121
Cost of midstream gas purchased		—		254,615	$	254,615
Operating costs and expenses		12,922		17,650	$	30,572
Depreciation, depletion and amortization		15,050		12,451		27,501

Operating income	$	55,143	$	22,290	$	77,433

Interest expense, net						(12,857	)
Derivatives						(11,676	)

Net income					$	52,900

Total assets	$	418,201	$	287,041	$	705,242

Additions to property and equipment and acquisitions	$	80,902	$	27,577	$	108,479

11.

Subsequent Events

On October 12, 2007, we purchased oil and gas royalty interests from Penn Virginia for $31.0 million. The royalty interests are associated with leases of property in Harlan and Letcher Counties, Kentucky and Lee, Scott and Wise Counties, Virginia and with estimated proved reserves of approximately 8.7 billion cubic feet of natural gas equivalent (Bcfe) at January 1, 2007. We funded the acquisition using our revolving credit facility.

In October 2007, we announced a $0.43 per unit distribution for the three months ended September 30, 2007, or $1.72 per unit on an annualized basis. The distribution will be paid on November 14, 2007 to unitholders of record at the close of business on November 5, 2007.

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. (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.” Our discussion and analysis include the following items:

•

Overview of Business

•

Acquisitions and Investments

•

Liquidity and Capital Resources

•

Results of Operations

•

Summary of Critical Accounting Policies and Estimates

•

Environmental Matters

•

Recent Accounting Pronouncements

•

Forward-Looking 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. Operating income was $81.5 million in the nine months ended September 30, 2007, compared to $77.4 million in the nine months ended September 30, 2006. In the nine months ended September 30, 2007, our coal and natural resource management segment contributed $53.2 million, or 65%, to operating income, and our natural gas midstream segment contributed $28.3 million, or 35%. 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 Nine Months Ended September 30, 2007:
Revenues	$	85,310	$	313,238	$	398,548
Cost of midstream gas purchased		—		251,000		251,000
Operating costs and expenses		15,489		19,966		35,455
Depreciation, depletion and amortization		16,643		13,957		30,600

Operating income	$	53,178	$	28,315	$	81,493

For the Nine Months Ended September 30, 2006:
Revenues	$	83,115	$	307,006	$	390,121
Cost of midstream gas purchased		—		254,615		254,615
Operating costs and expenses		12,922		17,650		30,572
Depreciation, depletion and amortization		15,050		12,451		27,501

Operating income	$	55,143	$	22,290	$	77,433

Coal and Natural Resource Management Segment

As of December 31, 2006, we owned or controlled approximately 765 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 coal mines. In the nine months ended September 30, 2007, our lessees produced 25.2 million tons of coal from our properties and paid us coal royalties revenues of $73.5 million, for an average gross coal royalty per ton of $2.92. Approximately 80% and 83% of our

coal royalties revenues in the nine months ended September 30, 2007 and 2006 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 lessee’s customers to change operations significantly or incur substantial costs. Fluctuations in production on subleased properties have a direct impact on coal royalties expense. 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 occurs as our lessees’ contracts are renegotiated.

We also earn revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their production levels and generate additional coal royalties revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through our joint venture with Massey Energy Company. In addition, we earn revenues from oil and gas royalty interests we own, from coal transportation, or wheelage, rights and from the sale of standing timber on our properties.

Our management continues to focus on acquisitions that increase and diversify our sources of cash flow. During the nine months ended September 30, 2007, we acquired 60 million tons of coal reserves in two coal reserve acquisitions with an aggregate purchase price of approximately $52 million. In addition, in September 2007, we acquired approximately 62,000 acres of forestland in West Virginia for a purchase price of approximately $93 million to expand our existing timber business. For a more detailed discussion of our acquisitions, see “—Acquisitions and Investments.”

Natural Gas Midstream Segment

We own and operate natural gas midstream assets located in Oklahoma and the panhandle of Texas. These assets include approximately 3,655 miles of natural gas gathering pipelines and three natural gas processing facilities having 160 million cubic feet per day (“MMcfd”) of total capacity. 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 the nine months ended September 30, 2007, system throughput volumes at our gas processing plants and gathering systems, including gathering-only volumes, were 50.8 billion cubic feet, or 186 MMcfd, and three of our natural gas midstream customers accounted for 53% of our natural gas midstream revenues.

Revenues, profitability and the future rate of growth of our natural gas midstream segment are highly dependent on market demand and prevailing natural gas liquid (“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 by contracting for natural gas that has been released from competitors’ systems. During 2007, we have expended $21.7 million on expansion projects to allow us to capitalize on such opportunities. The expansion projects include two natural gas processing facilities with a combined 140 MMcfd of inlet gas capacity.

Acquisitions and Investments

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. 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 capital improvements or acquisitions), scheduled debt payments and distribution payments. See Note 5 in the Notes to 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 the natural gas midstream market, some of which are beyond our control.

Cash Flows

The following table summarizes our cash flow statements for the nine months ended September 30, 2007 and 2006, consolidating our segments:



	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2007
Cash flows from operating activities:
Net income contribution	$	41,615		$	8,040		$	49,655
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		15,806			29,551			45,357
Net change in operating assets and liabilities		631			(9,307	)		(8,676	)

Net cash provided by operating activities	$	58,052		$	28,284			86,336

Net cash used in investing activities	$	(146,718	)	$	(28,619	)		(175,337	)

Net cash provided by financing activities								81,007

Net decrease in cash and cash equivalents							$	(7,994	)


	Coal and Natural Resource Management			Natural Gas Midstream			Consolidated
	(in thousands)
For the Nine Months Ended September 30, 2006
Net income contribution	$	41,693		$	11,207		$	52,900
Adjustments to reconcile net income to net cash provided by operating activities (summarized)		17,226			9,997			27,223
Net change in operating assets and liabilities		(7,337	)		2,638			(4,699	)

Net cash provided by operating activities	$	51,582		$	23,842			75,424

Net cash used in investing activities	$	(80,899	)	$	(27,547	)		(108,446	)

Net cash provided by financing activities								23,540

Net decrease in cash and cash equivalents							$	(9,482	)

Cash provided by operating activities increased by $10.9 million, or 15%, from $75.4 million in the nine months ended September 30, 2006 to $86.3 million in the same period in 2007. The overall increase in cash provided by operating activities was primarily attributable to an increase in our coal and natural resource management cash flows and, to a lesser extent, an increase in natural gas midstream processing cash flows.

During the nine months ended September 30, 2007, we made aggregate capital expenditures of $175.2 million primarily for coal reserve acquisitions, a forestland acquisition and natural gas midstream gathering system expansion projects. During the nine months ended September 30, 2006, we made aggregate capital expenditures of $108.4 million primarily for coal reserve acquisitions and the acquisition of pipeline and compression facilities. Capital expenditures comprise the primary portion of cash used in investing activities. The following table sets forth capital expenditures by segment made during the periods indicated:


	Nine Months Ended September 30,
	2007		2006
	(in thousands)
Coal and natural resource management
Acquisitions	$	145,878	$	66,580
Expansion capital expenditures		85		13,833
Other property and equipment expenditures		79		69

Total		146,042		80,482

Natural gas midstream
Acquisitions		—		14,626
Expansion capital expenditures		21,738		5,926
Other property and equipment expenditures		7,370		7,317

Total		29,108		27,869

Total capital expenditures	$	175,150	$	108,351

We funded capital expenditures in the nine months ended September 30, 2007 and 2006 with cash provided by operating activities and borrowings under our revolving credit facility. Borrowings, net of repayments, under our revolving credit facility funded $146.0 million and $71.5 million of the capital expenditures in the nine months ended September 30, 2007 and 2006, while cash provided by operating activities funded $29.2 million and $36.9 million of the capital expenditures in the nine months ended September 30, 2007 and 2006. Distributions to partners increased to $65.9 million in the nine months ended September 30, 2007 from $48.0 million in the nine months ended September 30, 2006 because we increased the quarterly unit distribution from $0.35 per unit to $0.42 per unit.

We borrowed $146.0 million, net of repayments, under our revolving credit facility in the nine months ended September 30, 2007, compared to borrowings, net of repayments, of $71.5 million in the nine months ended September 30, 2006. Funds from the borrowings were primarily used for capital expenditures.

Long-Term Debt

As of September 30, 2007, we had outstanding borrowings of $364.2 million, consisting of $300.2 million borrowed under our revolving credit facility and $64.0 million of senior unsecured notes (the “Notes”). The current portion of the Notes as of September 30, 2007 was $12.6 million.

Revolving Credit Facility. As of September 30, 2007, we had $300.2 million outstanding under our $450 million unsecured revolving credit facility (the “Revolver”) that matures in December 2011. The Revolver is available to us for general purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. We had outstanding letters of credit of $1.6 million as of September 30, 2007. At the current $450 million limit on the Revolver, and given our outstanding balance of $300.2 million, net of $1.6 million of letters of credit, we could borrow up to $148.2 million. In the nine months ended September 30, 2007, we incurred commitment fees of $0.5 million on the unused portion of the Revolver. On September 7, 2007, we increased the commitments under the Revolver from $300 million to $450 million. 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 the London Inter Bank Offering Rate (“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 during the nine months ended September 30, 2007 was 5.9%.

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 September 30, 2007, we were in compliance with all of our covenants under the Revolver.

Senior Unsecured Notes. As of September 30, 2007, we owed $64.0 million under the Notes. The Notes bear interest at a fixed rate of 6.02% and mature in March 2013, with semi-annual principal and interest payments. The Notes are equal in right of payment with all of our other unsecured indebtedness, including the Revolver. The Notes require us to obtain an annual confirmation of our credit rating, with a 1.00% increase in the interest rate payable on the Notes in the event that our credit rating falls below investment grade. In March 2007, our investment grade credit rating was confirmed by Dominion Bond Rating Services. The Notes contain various covenants similar to those contained in the Revolver. As of September 30, 2007, we were in compliance with all of our covenants under the Notes.

Interest Rate Swaps. In September 2005, we entered into interest rate swap agreements (the “Revolver Swaps”) with notional amounts totaling $60 million to establish fixed rates on the LIBOR-based portion of the outstanding balance of the Revolver until March 2010. We pay a weighted average fixed rate of 4.22% on the notional amount plus the applicable margin, and the counterparties pay a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. The Revolver Swaps were 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 1.00% in effect as September 30, 2007, the total interest rate on the $60 million portion of Revolver borrowings covered by the Revolver Swaps was 5.22% at September 30, 2007.

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 at the time. Including property acquisitions completed to date, we anticipate making capital expenditures in 2007 of $175.5 million to $185.7 million for coal reserve acquisitions, forestland acquisitions, oil and gas royalty acquisitions, coal services projects and other property and equipment and $50.0 million to $53.0 million for natural gas midstream system expansion projects and maintenance capital expenditures. We intend to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the Revolver. 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 periods indicated:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(in thousands, except per unit data)
Revenues	$	130,204	$	131,494	$	398,548	$	390,121
Expenses		98,433		101,596		317,055		312,688

Operating income	$	31,771	$	29,898	$	81,493	$	77,433
Net income	$	16,662	$	31,339	$	49,655	$	52,900
Net income per limited partner unit, basic and diluted	$	0.29	$	0.55	$	0.89	$	1.15
Cash flows provided by operating activities	$	29,020	$	24,905	$	86,336	$	75,424

Operating income increased in the three months ended September 30, 2007 compared to the same period in 2006 primarily due to a $3.6 million increase in natural gas midstream gross processing margin, a $0.4 million increase in coal services revenues and a $1.2 million decrease in operating expenses, partially offset by a $2.2 million decrease in coal royalties revenues and a $1.1 million increase in general and administrative expenses. Operating income increased in the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to an $8.3 million increase in natural gas midstream gross processing margin and a $1.3 million increase in coal services revenues, partially offset by a $2.3 million increase in operating expenses and a $2.1 million increase in general and administrative expenses.

Net income decreased in the three months ended September 30, 2007 compared to the same period in 2006 primarily due to a $17.1 million increase in derivative losses, partially offset by the $1.9 million increase in operating income and a $0.6 million decrease in interest expense. Net income decreased in the nine months ended September 30, 2007 compared to the same period in 2006 primarily due to a $9.3 million increase in derivative losses, partially offset by a $4.1 million increase in operating income and a $1.9 million decrease in interest expense.

Coal and Natural Resource Management Segment

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the periods indicated:


	Three Months Ended September 30,				% Change
	2007		2006		% Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	24,426	$	26,612	(8	%)
Coal services		1,955		1,515	29	%
Other		2,035		1,763	15	%

Total revenues		28,416		29,890	(5	%)

Expenses
Coal royalties expense		979		2,893	(66	%)
Other operating		1,020		447	128	%
Taxes other than income		242		154	57	%
General and administrative		2,630		2,095	26	%
Depreciation, depletion and amortization		5,833		5,551	5	%

Total expenses		10,704		11,140	(4	%)

Operating income	$	17,712	$	18,750	(6	%)

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		8,842		8,781	1	%
Average royalty per ton ($/ton)	$	2.76	$	3.03	(9	%)

Revenues.Coal royalties revenues decreased by $2.2 million, or 8%, from $26.6 million in the three months ended September 30, 2006 to $24.4 million in the same period in 2007. Tons produced by our lessees remained relatively constant in the three months ended September 30, 2007 compared to the same period in 2006. The mix of production shifted from the prior year’s quarter, with higher lessee production in the Illinois Basin, the San Juan Basin and Northern Appalachia, which have lower average coal royalties per ton, offset by lower lessee production in Central Appalachia, which has higher average coal royalties per ton. Primarily due to the combination of increased production in the relatively lower royalty rate Illinois Basin and reduced production in Central Appalachia, our average gross royalty per ton decreased by $0.27, or 9%, from $3.03 in the three months ended September 30, 2006 to $2.76 in the same period in 2007. Net of coal royalties expense, our average royalty per ton decreased $0.05, or 2%, from $2.70 in the three months ended September 30, 2006 to $2.65 in the same period in 2007.

The following table summarizes coal production and coal royalties revenues by property:


	Coal Production		Coal Royalties Revenues
	Three Months Ended September 30,		Three Months Ended September 30,
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	4,660	5,494	$	16,799	$	20,971
Northern Appalachia	1,338	1,305		2,051		1,893
Illinois Basin	1,292	550		2,470		1,055
San Juan Basin	1,552	1,432		3,106		2,693

Total	8,842	8,781	$	24,426	$	26,612

Coal services revenues increased by $0.5 million, or 29%, from $1.5 million in the three months ended September 30, 2006 to $2.0 million in the same period in 2007 primarily due to the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. In the three months ended September 30, 2007, the facility in Knott County, Kentucky contributed $0.4 million to coal services revenues.

Other revenues increased by $0.2 million, or 15%, from $1.8 million in the three months ended September 30, 2006 to $2.0 million in the same period in 2007 primarily due to an increase in wheelage income from our Central Appalachian properties.

Expenses.Coal royalties expense decreased by $1.9 million, or 66%, from $2.9 million in the three months ended September 30, 2006 to $1.0 million in the same period of 2007 primarily due to a decrease in production from property we sublease in Central Appalachia. Other operating expenses increased by $0.6 million, or 128%, from $0.4 million in the three months ended September 30, 2006 to $1.0 million in for the same period in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on our Central Appalachian and Illinois Basin properties. General and administrative expenses increased by $0.5 million, or 26%, from $2.1 million in the three months ended September 30, 2006 to $2.6 million in the same period in 2007 primarily due to increased staffing costs. Depreciation, depletion and amortization (“DD&A”) expenses increased by $0.2 million, or 5%, from $5.6 million in the three months ended September 30, 2006 to $5.8 million in the same period in 2007 primarily due to depreciation on new coal services facilities.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our coal and natural resource management segment and the percentage change for the periods indicated:


	Nine Months Ended				%
	September 30,				%
	2007		2006		Change
	(in thousands, except as noted)
Financial Highlights
Revenues
Coal royalties	$	73,455	$	73,288	0	%
Coal services		5,648		4,345	30	%
Other		6,207		5,482	13	%

Total revenues		85,310		83,115	3	%

Expenses
Coal royalties expense		4,582		4,411	4	%
Other operating		2,086		1,152	81	%
Taxes other than income		832		565	47	%
General and administrative		7,989		6,794	18	%
Depreciation, depletion and amortization		16,643		15,050	11	%

Total expenses		32,132		27,972	15	%

Operating income	$	53,178	$	55,143	(4	%)

Operating Statistics
Royalty coal tons produced by lessees (tons in thousands)		25,186		24,467	3	%
Average royalty per ton ($/ton)	$	2.92	$	3.00	(3	%)

Revenues. Coal royalties revenues remained relatively constant in the nine months ended September 30, 2007 compared to the same period in 2006. Tons produced by our lessees increased by 0.7 million tons, or 3%, from 24.5 million tons in the nine months ended September 30, 2006 to 25.2 million tons in the same period in 2007. Our average gross royalty per ton decreased by $0.08, or 3%, from $3.00 in the nine months ended September 30, 2006 to $2.92 in the same period in 2007. Net of coal royalties expense, our average royalty per ton decreased $0.09, or 3%, from $2.82 in the nine months ended September 30, 2006 to $2.73 in the same period in 2007. This decrease was primarily due to a shift in the mix of coal production by our lessees, with higher lessee production in the Illinois Basin and the San Juan Basin, which have lower average coal royalties per ton, partially offset by lower lessee production in Central Appalachia, which has higher average coal royalties per ton.

The following table summarizes coal production and coal royalties revenues by property:


	Coal Production		Coal Royalties Revenues
	Nine Months Ended		Nine Months Ended
	September 30,		September 30,
Property	2007	2006	2007		2006
	(tons in thousands)		(in thousands)
Central Appalachia	14,635	14,933	$	53,983	$	56,892
Northern Appalachia	3,787	3,929		5,808		5,746
Illinois Basin	2,413	1,891		4,957		3,666
San Juan Basin	4,351	3,714		8,707		6,984

Total	25,186	24,467	$	73,455	$	73,288

Coal services revenues increased by $1.3 million, or 30%, from $4.3 million in the nine months ended September 30, 2006 to $5.6 million in the same period in 2007 primarily due the completed construction of a coal services facility in Knott County, Kentucky, which began operations in October 2006. In the nine months ended September 30, 2007, the facility in Knott County, Kentucky contributed $1.1 million to coal services revenues.

Other revenues increased by $0.7 million, or 13%, from $5.5 million in the nine months ended September 30, 2006 to $6.2 million in the same period in 2007 primarily due to an increase in wheelage income from our Central Appalachian properties.

Expenses.Coal royalties expense increased by $0.2 million, or 4%, from $4.4 million in the nine months ended September 30, 2006 to $4.6 million in the same period in 2007 primarily due to an increase in production from property we sublease in Central Appalachia. Other operating expenses increased by $0.9 million, or 81%, from $1.2 million in the nine months ended September 30, 2006 to $2.1 million in the same period in 2007 primarily due to an increase in mine maintenance and core-hole drilling expenses on our central Appalachian and Illinois Basin properties. General and administrative expenses increased by $1.2 million, or 18%, from $6.8 million in the nine months ended September 30, 2006 to $8.0 million in the same period in 2007 primarily due to increased staffing costs and corporate reimbursements to our general partner. DD&A expenses increased by $1.5 million, or 11%, from $15.1 million in the nine months ended September 30, 2006 to $16.6 million in the same period in 2007 primarily due to depreciation on new coal services facilities.

Natural Gas Midstream Segment

Three Months Ended September 30, 2007 Compared to Three Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods indicated:


	Three Months Ended September 30,
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	52,343	$	62,408	(16	%)
Natural gas liquids		42,510		35,363	20	%
Condensate		3,251		2,323	40	%
Gathering and transportation fees		2,266		715	217	%

Total natural gas midstream revenues		100,370		100,809	(0	%)
Producer services		1,418		795	78	%

Total revenues		101,788		101,604	0	%

Expenses
Cost of midstream gas purchased		76,192		80,272	(5	%)
Operating		3,225		3,038	6	%
Taxes other than income		424		329	29	%
General and administrative		3,076		2,504	23	%
Depreciation and amortization		4,812		4,313	12	%

Total operating expenses		87,729		90,456	(3	%)

Operating income	$	14,059	$	11,148	26	%

Operating Statistics
System throughput volumes (MMcf)		17,844		16,586	8	%
Gross processing margin	$	24,178	$	20,537	18	%

Revenues. Natural gas midstream revenues remained relatively constant in the three months ended September 30, 2007 compared to the same period in 2006. 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, gathering and other fees primarily from natural gas volumes connected to our gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants. The pricing environment was such that the decrease in our realized prices for natural gas was offset by increases in our realized prices for NGLs and condensate. Gathering and transportation revenues benefited from a short-term gathering contract that was entered into and completed during the three months ended September 30, 2007. These gathered volumes contributed to our overall system throughput increase, but did not result in a corresponding increase in throughput volumes at our processing plants because the volumes were delivered off of the gathering system prior to reaching the processing plant.

Producer services revenues increased by $0.6 million, or 78%, from $0.8 million in the three months ended September 30, 2006 to $1.4 million in the same period in 2007 primarily due to an increase in marketed gas volumes.

Expenses. Operating costs and expenses decreased due to a decrease in the cost of midstream gas purchased, partially offset by minor increases in operating expenses, taxes other than income, general and administrative expenses and DD&A expenses.

Cost of midstream gas purchased decreased by $4.1 million, or 5%, from $80.3 million in the three months ended September 30, 2006 to $76.2 million in the same period in 2007 primarily due to the decrease in realized natural gas prices. 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.

Our gross processing margin is the difference between our natural gas midstream revenues and our cost of midstream gas purchased. Our gross processing margin increased by $3.7 million, or 18%, from $20.5 million in the three months ended September 30, 2006 to $24.2 million in the same period in 2007 primarily due to a higher frac spread caused by higher NGL sale prices and lower natural gas purchase prices.

System throughput volumes at our gas processing plants and gathering systems increased by 14 MMcfd, or 8%, from 180 MMcfd in the three months ended September 30, 2006 to 194 MMcfd in the same period in 2007 primarily due to a short-term gathering contract that was entered into and completed in the third quarter of 2007.

Our natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the three months ended September 30, 2007, 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. The following table shows a summary of the effects of derivative activities on our gross processing margin:


	Three Months Ended September 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	24,178		$	20,537
Derivatives (gains) losses included in gross processing margin		1,304			825

Gross processing margin before impact of derivatives		25,482			21,362
Cash settlements on derivatives		(4,702	)		(7,344	)

Gross processing margin, adjusted for derivatives	$	20,780		$	14,018

Operating expenses increased by $0.2 million, or 6%, from $3.0 million in the three months ended September 30, 2006 to $3.2 million in the same period in 2007. DD&A expenses increased by $0.5 million, or 12%, from $4.3 million in the three months ended September 30, 2006 to $4.8 million in the same period in 2007. Both increases were due to acquisitions and gathering system construction. General and administrative expenses increased by $0.6 million, or 23%, from $2.5 million in the three months ended September 30, 2006 to $3.1 million in the same period in 2007 primarily due to increased staffing costs.

Nine Months Ended September 30, 2007 Compared to Nine Months Ended September 30, 2006

The following table sets forth a summary of certain financial and other data for our natural gas midstream segment and the percentage change for the periods indicated:


	Nine Months Ended September 30,
	2007		2006		% Change
	(in thousands)
Financial Highlights
Revenues
Residue gas	$	181,407	$	199,096	(9	%)
Natural gas liquids		115,660		97,591	19	%
Condensate		9,324		7,165	30	%
Gathering and transportation fees		3,704		1,488	149	%

Total natural gas midstream revenues		310,095		305,340	2	%
Producer services		3,143		1,666	89	%

Total revenues		313,238		307,006	2	%

Expenses
Cost of midstream gas purchased		251,000		254,615	(1	%)
Operating		9,567		8,387	14	%
Taxes other than income		1,280		1,054	21	%
General and administrative		9,119		8,209	11	%
Depreciation and amortization		13,957		12,451	12	%

Total operating expenses		284,923		284,716	0	%

Operating income	$	28,315	$	22,290	27	%

Operating Statistics
System throughput volumes (MMcf)		50,763		45,234	12	%
Gross processing margin	$	59,095	$	50,725	17	%

Revenues. Natural gas midstream revenues increased by $4.8 million, or 2%, from $305.3 million in the nine months ended September 30, 2006 to $310.1 million in the same period in 2007 primarily due to a more favorable pricing environment combined with increased system throughput volumes. A June 2006 pipeline acquisition and a short-term gathering contract that was entered into and completed during third quarter of 2007 contributed to the volume increase. 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, gathering and other fees primarily from natural gas volumes connected to our gas processing plants and the purchase and resale of natural gas not connected to our gathering systems and processing plants.

Producer services revenues increased by $1.4 million, or 89%, from $1.7 million in the nine months ended September 30, 2006 to $3.1 million in the same period in 2007 primarily due to an increase in marketed gas volumes.

Expenses. Operating costs and expenses were relatively constant in the nine months ended September 30, 2007 compared to the same period in 2006.

Cost of midstream gas purchased decreased by $3.6 million, or 1%, from $254.6 million in the nine months ended September 30, 2006 to $251.0 million in the same period in 2007. There was a $4.6 million non-cash charge recorded to reserves in the nine months ended September 30, 2006 for amounts related to balances assumed as part of the acquisition of our natural gas midstream business in 2005. Excluding this reserve, the cost of midstream gas purchased increased for the comparative periods. Higher volumes, partially offset by lower realized natural gas prices, accounted for the increase, excluding the non-cash charge, in the cost of midstream gas purchased. 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.

Our gross processing margin for our natural gas midstream operations increased by $8.4 million, or 17%, from $50.7 million in the nine months ended September 30, 2006 to $59.1 million in the same period in 2007 primarily due to a more favorable pricing environment and higher system throughput volumes.

System throughput volumes at our gas processing plants and gathering systems increased by 20 MMcfd, or 12%, from 166 MMcfd in the nine months ended September 30, 2006 to 186 MMcfd in the same period in 2007 primarily due to the June 2006 pipeline acquisition, a short-term gathering contract that was entered into and completed in the third quarter of 2007, successful drilling of local producers and expansion of our current facilities.

Our natural gas midstream business generates revenues primarily from gas purchase and processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. During the nine months ended September 30, 2007, 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. The following table shows a summary of the effects of derivative activities on our gross processing margin:


	Nine Months Ended September 30,
	2007			2006
	(in thousands)
Gross processing margin, as reported	$	59,095		$	50,725
Derivatives (gains) losses included in gross processing margin		3,432			1,275

Gross processing margin before impact of derivatives		62,527			52,000
Cash settlements on derivatives		(8,963	)		(15,405	)

Gross processing margin, adjusted for derivatives	$	53,564		$	36,595

Operating expenses increased by $1.2 million, or 14%, from $8.4 million in the nine months ended September 30, 2006 to $9.6 million in the same period in 2007. DD&A expenses increased by $1.5 million, or 12%, from $12.5 million in the nine months ended September 30, 2006 to $14.0 million in the same period in 2007. Both increases were due to acquisitions and gathering system construction. General and administrative expenses increased by $0.9 million, or 11%, from $8.2 million in the nine months ended September 30, 2006 to $9.1 million in the same period in 2007 primarily due to increased staffing costs.

Other

Interest Expense. Interest expense decreased by $0.6 million, or 11%, from $5.3 million in the three months ended September 30, 2006 to $4.7 million in the same period in 2007. Interest expense decreased by $1.9 million,

or 14%, from $13.8 million in the nine months ended September 30, 2006 to $11.8 million in the same period in 2007. The decreases in both periods were primarily due to our making a $114.6 million principal payment on our revolving credit facility in December 2006.

Derivatives. Derivative losses increased by $17.1 million, or 268%, from a $6.4 million gain in the three months ended September 30, 2006 to a $10.7 million loss in the same period in 2007. Derivative losses increased by $9.2 million, or 79%, from $11.7 million in the nine months ended September 30, 2006 to $20.9 million in the same period in 2007. The increases in both periods were primarily due to valuation adjustments of unrealized derivative positions using mark-to-market accounting.

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

Revenues from the sale of NGLs and residue gas are recognized when the NGLs and residue gas produced at our gas processing plants are sold. Gathering and transportation revenues are recognized 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, accruals for revenues and accounts receivable and the related cost of midstream gas purchased and accounts payable are made based on estimates of natural gas purchased and NGLs and natural gas sold, and our financial results include estimates of production and revenues for the period of actual production. Any differences, which we do not expect to be significant, between the actual amounts ultimately received or paid and the original estimates are recorded in the period they become finalized.

Coal Royalties Revenues

Coal royalties revenues are recognized 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. Any differences, which we do not expect to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

Derivative Activities

We historically have entered into derivative financial instruments that would qualify for hedge accounting under Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities. Hedge accounting affects the timing of revenue recognition and cost of midstream gas purchased in our condensed consolidated statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred until the related hedged transaction settles. Because during the first quarter of 2006 our natural gas derivatives and a large portion of our NGL derivatives no longer qualified for hedge accounting and to increase clarity in our condensed consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses 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 could experience significant changes in the estimate of derivative gain or loss recognized in revenues and cost of midstream gas purchased due to swings in the value of these contracts. These fluctuations could be significant in a volatile pricing environment.

The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged

transactions settle. We expect to recognize hedging losses of $1.2 million for the remainder of 2007 and $5.5 million for 2008 related to such settlements. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and gas prices.

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 outside consultants. Our estimates of coal reserves are updated annually and may result in adjustments to coal reserves and depletion rates that are recognized prospectively.

Goodwill

Under SFAS No. 141,Business Combinations, and SFAS No. 142,Goodwill and Other Intangible Assets, 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.

Intangibles

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.

Environmental Matters

To dispose of mining overburden generated by their surface mining activities, our lessees need to obtain government approvals, including Federal Clean Water Act (“CWA”) Section 404 permits to construct valley fills and sediment control ponds. Two CWA Section 404 permits issued to Alex Energy, Inc. (“Alex Energy”), one of our surface coal mine lessees in West Virginia, were recently challenged in a lawsuit,Ohio Valley Environmental Coalition (“OVEC”) v. United States Army Corps of Engineers. On March 23, 2007, the U.S. District Court for the Southern District of West Virginia rescinded and remanded the permit authorizing several valley fills and sediment ponds that may be constructed at the Republic No. 2 Mine and enjoined Alex Energy from taking any further actions under this permit. The district court has yet to rule on whether the other CWA Section 404 permit for the construction of valley fills and associated sediment ponds at the Republic No. 1 Mine was also invalidly issued. Although portions of the Republic No. 2 Mine continue to operate based on a subsequent order allowing the mine to fully utilize and complete some of its partially constructed valley fills, the construction of new valley fills at other portions of the Republic No. 2 Mine is enjoined pending a final outcome of this litigation. On June 13, 2007, the

district court also issued a declaratory judgment indicating that the mining companies subject to theOVEC decision may also be required to obtain new, separate CWA Section 402 permit authorizations for the stream segments located between the toes of their valley fills and their respective sediment pond embankments.

The district court’s March 23, 2007 decision is currently on appeal to the U.S. Court of Appeals for the Fourth Circuit. While we are still reviewing the district court’s ruling, our lessees may not be able to obtain or may experience delays in securing additional CWA Section 404 permits for surface mining operations. Unless theOVEC decision is overturned or further limited in subsequent proceedings, the ruling and its collateral consequences could ultimately have an adverse effect on our coal royalties revenues.

Recent Accounting Pronouncements

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

Forward-Looking Statements

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

•

our ability to generate sufficient cash from our natural gas midstream and coal and natural resource management businesses to pay the minimum quarterly distribution to our general partner and our unitholders;

•

energy prices generally and specifically, the price of natural gas, NGLs and coal;

•

the relationship between natural gas and NGL prices;

•

the price of coal and its comparison to the price of natural gas;

•

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

•

the projected demand for coal, natural gas and NGLs;

•

the projected supply of coal, natural gas and NGLs;

•

our ability to acquire new coal reserves or natural gas midstream assets on satisfactory terms;

•

the price for which we can acquire coal reserves;

•

our ability to continually find and contract for new sources of natural gas supply;

•

our ability to retain existing or acquire new natural gas midstream customers;

•

our ability to lease new and existing coal reserves;

•

the ability of our lessees to produce sufficient quantities of coal on an economic basis from our reserves;

•

the ability of our lessees to obtain favorable contracts for coal produced from our reserves;

•

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

•

our exposure to the credit risk of our coal lessees and natural gas midstream customers;

•

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

•

hazards or operating risks incidental to natural gas midstream operations;

•

unanticipated geological problems;

•

the dependence of our natural gas midstream business on having connections to third party pipelines;

•

the availability of production equipment and materials;

•

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

•

the failure of our infrastructure and our lessees’ mining equipment or processes to operate in accordance with specifications or expectations;

•

delays in anticipated start-up dates of our lessees’ mining operations and related coal infrastructure projects;

•

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;

•

the risks associated with having or not having price risk management programs;

•

labor relations and costs;

•

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

•

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

•

our ability to expand our natural gas midstream business by constructing new gathering systems, pipelines and processing facilities on an economic basis and in a timely manner;

•

coal handling joint venture operations;

•

changes in financial market conditions; and

•

other risks set forth in Item 1A, “Risk Factors,” of our Annual Report on Form 10-K for the year ended December 31, 2006.

Additional information concerning these and other factors can be found in our press releases and public periodic filings with the Securities and Exchange Commission, including our Annual Report on Form 10-K for the year ended December 31, 2006. 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 NGL, crude oil, natural gas 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 value of our price risk management assets is significantly affected by fluctuations in the prices of natural gas, NGLs and crude oil.

For the nine months ended September 30, 2007, we reported a net $20.9 million derivative loss for mark-to-market adjustments. Because during the first quarter of 2006 our natural gas derivatives and a large portion of our NGL derivatives no longer qualified for hedge accounting and to increase clarity in our condensed consolidated financial statements, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in future earnings through 2008 as the original hedged transactions settle. We expect to recognize hedging losses of $1.2 million for the remainder of 2007 and $5.5 million for 2008 related to such settlements. The discontinuation of hedge accounting will have no impact on our reported cash flows, although future results of operations will be affected by the potential volatility of mark-to-market gains and losses which fluctuate with changes in NGL, oil and natural gas prices. See the discussion and tables in Note 4 in the Notes to Condensed Consolidated Financial Statements for a description of our derivatives program.

The following table lists our open mark-to-market derivative agreements and their fair values as of September 30, 2007:


	Average Volume Per Day		Weighted Average Price			Weighted Average Price Collars				Estimated Fair Value
	Average Volume Per Day		Weighted Average Price			Put		Call		Estimated Fair Value
										(in thousands)
Ethane Swaps	(in gallons	)		(per gallon	)
Fourth quarter 2007	34,440		$	0.5050						$	(1,240	)
First quarter 2008 through fourth quarter 2008	34,440		$	0.4700							(3,299	)
Propane Swaps	(in gallons	)		(per gallon	)
Fourth quarter 2007	26,040		$	0.7550							(1,384	)
First quarter 2008 through fourth quarter 2008	26,040		$	0.7175							(4,592	)
Crude Oil Swaps	(in barrels	)		(per barrel	)
Fourth quarter 2007	560		$	50.80							(1,502	)
First quarter 2008 through fourth quarter 2008	560		$	49.27							(5,355	)
Natural Gas Swaps (Purchase)	(in MMbtu	)		(per MMbtu	)
Fourth quarter 2007 through fourth quarter 2008	4,000		$	6.97							1,405
Natural Gasoline Swap/Crude Oil Swap (purchase)	(in gallons / in barrels	)		(per gallon / per barrel	)
Fourth quarter 2007	23,520 / 560			1.265 / 57.12							33
Ethane Collar	(in gallons	)					(per gallon)
Fourth quarter 2007	5,000					$	0.6100	$	0.7125		(88	)
Propane Collar	(in gallons	)					(per gallon)
Fourth quarter 2007	9,000					$	1.0300	$	1.1640		(148	)
Natural Gasoline Collar	(in gallons	)					(per gallon)
Fourth quarter 2007 through fourth quarter 2008	6,300					$	1.4800	$	1.6465		(366	)
Crude Oil Collar	(in barrels	)					(per barrel)
First quarter 2008 through fourth quarter 2008	400					$	65.00	$	75.25		(600	)
Frac Spread	(in MMbtu	)		(per MMbtu	)
Fourth quarter 2007	7,128		$	4.55							(2,601	)
First quarter 2008 through fourth quarter 2008	4,193		$	4.30							(1,933	)
First quarter 2008 through fourth quarter 2008 - (a)	3,631		$	5.85							—
Settlements to be paid in subsequent period											(2,428	)

Natural gas midstream segment commodity derivatives - net liability										$	(24,098	)

(a) – Entered into in October 2007

Interest Rate Risk

As of September 30, 2007, we had $300.2 million of outstanding indebtedness under the Revolver, which carries a variable interest rate throughout its term. We entered into the Revolver Swaps in September 2005 to effectively convert the interest rate on $60 million of the amount outstanding under the Revolver from a LIBOR-based floating rate to a weighted average fixed rate of 4.22% 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 September 30, 2007 would cost us approximately $2.4 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 September 30, 2007. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Exchange Act is recorded, processed, summarized and reported accurately and on a timely basis. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that, as of September 30, 2007, such disclosure controls and procedures were effective.

(b)

Changes in Internal Control over Financial Reporting

On July 1, 2007, our general partner migrated to a new enterprise resource planning (“ERP”) system. As a result of moving to the new ERP system, several process level control procedures were changed in order to conform to the new ERP system. While our general partner believes that the new ERP system will ultimately strengthen our internal control over financial reporting, there are inherent weaknesses in implementing any new system and we could experience control and implementation issues impacting our financial reporting. In the event that such an issue occurs, our general partner has manual procedures in place which would allow it to continue to record and report results from the new ERP system. Our general partner is continuing to implement additional features and aspects of its new ERP system and will monitor, test and evaluate the impact and effect of the new ERP system on our internal controls and procedures as part of the evaluation of our internal control over financial reporting for 2007. Except for the new ERP system implementation, there were no changes made in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Items 1, 1A, 2, 3, 4 and 5 are not applicable and have been omitted.

Item 6

Exhibits

2.1	Purchase and Sale Agreement dated as of August 23, 2007 among Penn Virginia Operating Co., LLC and MeadWestvaco Corporation (incorporated by reference to Exhibit 2.1 to Registrant’s Current Report on Form 8-K filed on September 24, 2007).

4.1

Third Amendment to Note Purchase Agreement and Parent Guaranty dated as of September 19, 2007 among Penn Virginia Operating Co., LLC, Penn Virginia Resource Partners, L.P. and the noteholders party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 20, 2007).

10.1

Fourth Amendment to Amended and Restated Credit Agreement dated as of September 7, 2007 among Penn Virginia Operating Co., LLC, PNC Bank, National Association, as agent, and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to Registrant’s Current Report on Form 8-K filed on September 7, 2007).

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

31.1	Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification Pursuant to 18 U.S.C. Section 1350, 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: November 1, 2007	By:	/s/ Frank A. Pici
		Frank A. Pici
		Vice President and Chief Financial Officer

Date: November 1, 2007	By:	/s/ Forrest W. McNair
		Forrest W. McNair
		Vice President and Controller

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	H.S. freshman Good

PVR Partners, L. P. (PVR) Inactive 10-Q2007 Q3 Quarterly report

Content analysis

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents