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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended September 30, 2008

or

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)

(610) 687-8900

(Registrant’s telephone number, including area code)

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

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

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

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

As of November 5, 2008, 51,798,895 common limited partner units were outstanding.

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX

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PART I. FINANCIAL INFORMATION

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED BALANCE SHEETS – unaudited

(in thousands)

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS – unaudited

(in thousands)

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – unaudited

September 30, 2008

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

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

Our natural gas midstream segment is engaged in providing natural gas processing, gathering and other related services. We own and operate natural gas midstream assets located in Oklahoma and Texas. Our natural gas midstream business derives revenues primarily from gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We also own a natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems and at market hubs accessed by various interstate pipelines.

Our general partner is Penn Virginia Resource GP, LLC, which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. (“PVG”), a publicly traded Delaware limited partnership. At September 30, 2008, Penn Virginia owned an approximately 77% limited partner interest in PVG, as well as the non-economic general partner interest in PVG. At September 30, 2008, PVG owned an approximately 37% limited partner interest in us as well as 100% of our general partner, which owns a 2% general partner interest in us.

Our accounting policies are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2007. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

Our condensed consolidated financial statements include the accounts of the Partnership and all of our wholly owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Our condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim financial reporting and Securities and Exchange Commission (“SEC”) regulations. These statements involve the use of estimates and judgments where appropriate. In the opinion of management, all adjustments, consisting of normal recurring accruals, considered necessary for a fair presentation of our condensed consolidated financial statements have been included. These financial statements should be read in conjunction with our condensed consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2007. Operating results for the three and nine months ended September 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

New Accounting Standards

In March 2008, the Emerging Issues Task Force (“EITF”) ratified EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128 to Master Limited Partnerships (“EITF 07-4”), which states that incentive distribution rights (“IDRs”) in a typical master limited partnership are participating securities under Statement of Financial Accounting Standards (“SFAS”) No. 128, Earnings Per Share. According to EITF 07-4, when current-period earnings exceed cash distributions and the IDR is

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embedded in the general partner interest, undistributed earnings should not be allocated to the general partner (including embedded IDRs) and limited partners. Under the current accounting guidance, when current-period earnings exceed cash distributions and the IDR is embedded in the general partner interest, undistributed earnings should be allocated to the general partner. For the three and nine months ended September 30, 2008 and 2007, current-period earnings did not exceed cash distributions. See Note 7 – Partners’ Capital and Distributions. EITF 07-4 will be effective for fiscal years beginning after December 15, 2008 and applied retrospectively to all periods presented. Early application is not permitted. EITF 07-4 will eliminate our need to adjust our earnings per unit calculation in periods where current period earnings exceed distributions.

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

Lone Star Gathering, L.P.

On July 17, 2008, we completed an acquisition of substantially all of the assets of Lone Star Gathering, L.P. (“Lone Star Acquisition”). Lone Star’s assets are located in the southern portion of the Fort Worth Basin of North Texas and include approximately 129 miles of gas gathering pipelines and approximately 240,000 acres dedicated by active producers. The Lone Star Acquisition expands the geographic scope of the natural gas midstream segment into the Barnett Shale play in the Fort Worth Basin.

We acquired this business for approximately $164.3 million and a liability of $4.7 million, which represents the fair value of a $5.0 million guaranteed payment, plus contingent payments of $30.0 million and $25.0 million. Funding for the acquisition was provided by $80.7 million of borrowings under our revolving credit facility (the “Revolver”), 2,009,995 PVG common units (which we purchased from two subsidiaries of Penn Virginia for $61.8 million) and 542,610 of our newly issued common units.

The contingent payments will be triggered if revenues from certain assets located in a defined geographic area reach certain targets by or before June 30, 2013 and will be funded in cash or common units, at our election.

The Lone Star Acquisition has been accounted for using the purchase method of accounting in accordance with SFAS No. 141, Business Combinations. Under the purchase method of accounting, the total purchase price has been preliminarily allocated to the net tangible and intangible assets acquired from Lone Star based on their estimated fair values. The allocations of purchase consideration are subject to change pending further review of the fair value of the assets acquired and liabilities assumed and actual transaction costs. The purchase price allocation is preliminary due to our continual assessment of potentially assumed asset retirement obligations that we may incur and review of certain contracts. The purchase price allocation will be finalized for any potential assets or liabilities related to the assets acquired in the Lone Star Acquisition. The total purchase price was allocated to the assets purchased based upon preliminary fair values on the date of the Lone Star Acquisition as follows:

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The preliminary purchase price includes approximately $11.2 million of goodwill, all of which has been allocated to the natural gas midstream segment. A significant factor that contributed to the recognition of goodwill includes the ability to acquire an established business on the western border of the expanding Barnett Shale play in the Fort Worth Basin. Under SFAS No. 141 and SFAS 142, Goodwill and Other Intangible Assets, goodwill recorded in connection with a business combination is not amortized, but is tested for impairment at least annually. Accordingly, the accompanying pro forma combined income statement does not include amortization of the goodwill recorded in the acquisition. The preliminary purchase price includes approximately $69.2 million of intangible assets that are associated with assumed contracts and customer relationships. These intangible assets will be amortized over the period in which benefits are derived from the contracts and relationships assumed and will be reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. We estimate the useful lives of these intangible assets to be 20 years.

The following pro forma financial information reflects the consolidated results of our operations as if the Lone Star Acquisition had occurred on January 1 of the reported period. The pro forma information includes adjustments primarily for depreciation of acquired property and equipment, the amortization of intangible assets, interest expense for acquisition debt and the change in weighted average common units resulting from the issuance of 542,610 of our newly issued common units given as consideration in the Lone Star Acquisition. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date:

Thunder Creek Gas Services, LLC

In April 2008, we acquired a 25% member interest in Thunder Creek Gas Services, LLC (“Thunder Creek”), a joint venture that gathers and transports coalbed methane in Wyoming’s Powder River Basin for $51.6 million in cash, after customary closing adjustments. Funding for the acquisition was provided by borrowings under the Revolver. The entire member interest is recorded in equity investments on the condensed consolidated balance sheet. This investment includes $37.3 million of fair value for the net assets acquired and $14.3 million of fair value paid in excess of our portion of the underlying equity in the net assets acquired related to customer contracts and related customer relations. This excess is being amortized to equity earnings over the life of the underlying contracts. The earnings are recorded in other revenues on the condensed consolidated statements of income.

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Based on our analysis of the fair value of this acquisition, we did not deem our acquisition of Thunder Creek to be a material business combination and therefore are not disclosing pro forma financial information in accordance with SFAS No. 141.

In 2008, we issued to the public 5.15 million common units to the public representing limited partner interests in us and received $138.0 million in net proceeds. We received total contributions of $2.9 million from our general partner to maintain its 2% general partner interest. We used net proceeds to repay a portion of our borrowings under the Revolver.

We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008, for financial assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets and financial liabilities that are being measured and reported on a fair value basis. SFAS No. 157 defines fair value, establishes a framework for measuring fair value and requires enhanced disclosures about fair value measurements. FASB Staff Position FAS 157-2, Effective Date of FASB Statement No. 157 (“FSP SFAS 157-2”), delays the application of SFAS No. 157 for nonfinancial assets and nonfinancial liabilities to fiscal years and interim periods beginning after November 15, 2008. Examples of nonfinancial assets for which this FASB Staff Position delays application of SFAS No. 157 include business combinations, impairment and initial recognition of asset retirement obligations. We are currently assessing the impact on the financial statements of adopting FSP SFAS 157-2 effective January 1, 2009.

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

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

See Note 6 – Derivative Instruments, for the effects of these instruments on our condensed consolidated statements of income.

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

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Natural Gas Midstream Segment Commodity Derivatives

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

The counterparty to a costless collar contract is required to make a payment to us if the settlement price for any settlement period is below the floor price for such contract. We are required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price for such contract. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor price and equal to or less than the ceiling price for such contract. The counterparty to a swap contract is required to make a payment to us if the settlement price for any settlement period is less than the swap price for such contract, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price for such contract.

A three-way option contract consists of a collar contract as described above plus a put option contract sold by us with a price below the floor price of the collar. This additional put requires us to make a payment to the counterparty if the settlement price for any settlement period is below the put option price. By combining the collar contract with the additional put option, we are entitled to a net payment equal to the difference between the floor price of the collar contract and the additional put option price if the settlement price is equal to or less than the additional put option price. If the settlement price is greater than the additional put option price, the result is the same as it would have been with a collar contract only. This strategy enables us to increase the floor and the ceiling prices of the collar beyond the range of a traditional collar contract while defraying the associated cost with the sale of the additional put option.

We determine the fair values of our derivative agreements based on forward price quotes for the respective commodities as of September 30, 2008, the credit risk of our counterparties and our own credit risk. The following table sets forth our positions as of September 30, 2008 for commodities related to natural gas midstream revenues and cost of midstream gas purchased:

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At September 30, 2008, we reported a (i) net derivative liability related to the natural gas midstream segment of $11.7 million and (ii) loss in accumulated other comprehensive income (“AOCI”) of $1.4 million related to derivatives in the natural gas midstream segment for which we discontinued hedge accounting in 2006. The $1.4 million loss will be recorded in earnings through the end of 2008 as the hedged transactions settle. See the Adoption of SFAS No. 161 section below for the impact of the natural gas midstream commodity derivatives on our condensed consolidated statements of income.

Interest Rate Swaps

We have entered into the Revolver Swaps to establish fixed rates on a portion of the outstanding borrowings under the Revolver. Until March 2010, the notional amounts of the Revolver Swaps total $210.0 million, or approximately 38% of our total long-term debt outstanding as of September 30, 2008, with us paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month London Interbank Offered Rate (“LIBOR”). From March 2010 to December 2011, the notional amounts of the Revolver Swaps total $150.0 million with us paying a weighted average fixed rate of 4.23% on the notional amount, and the counterparties paying a variable rate equal to the three-month LIBOR. Settlements on the Revolver Swaps are recorded as interest expense. Certain of our Revolver Swaps are designated as cash flow hedges. Accordingly, the effective portion of the change in the fair value of the transactions for the swaps that are designated as cash flow hedges are recorded each period in AOCI. We reported a (i) derivative liability of $3.4 million at September 30, 2008 and (ii) loss in AOCI of $2.0 million at September 30, 2008 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.8 million and $1.2 million in net hedging losses in interest expense for the three and nine months ended September 30, 2008.

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Adoption of SFAS No. 161

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

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

Cash paid for commodity derivatives is included on the Derivatives line on our condensed consolidated statement of income, and cash paid for interest rate swaps is included on the Interest expense line on our condensed consolidated statement of income.

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

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

The above derivative activity represents cash flow hedges. As of September 30, 2008, none of our derivative instruments were classified as fair value hedges or trading securities. In addition, as of September 30, 2008, none of our derivative instruments contained credit risk contingencies.

As of September 30, 2008, partners’ capital consisted of 51.8 million common units, representing a 98% limited partner interest and a 2% general partner interest. As of September 30, 2008, affiliates of Penn Virginia, in the aggregate, owned a 39% interest in us, consisting of 19.7 million common units and a 2% general partner interest.

Subordinated Units

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

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Net Income per Limited Partner Unit

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

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

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

Cash Distributions

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

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

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

In February 2008, the board of directors of our general partner paid a quarterly distribution of $0.44 per unit to our unitholders ($1.76 per unit on an annualized basis). In May 2008, the board of directors of our general partner paid a $0.45 per unit quarterly distribution to our unitholders ($1.80 per unit on an annualized basis). In August 2008, the board of directors of our general partner paid a quarterly distribution of $0.46 per unit to our unitholders ($1.84 per unit on an annualized basis). In October 2008, the board of directors of our general partner declared a quarterly distribution of $0.47 per unit ($1.88 per unit on an annualized basis). The distribution will be paid on November 14, 2008 to unitholders of record at the close of business on November 6, 2008.

Limited Call Right

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

In July 2008, we paid an aggregate of $63.3 million to the holders of our Senior Unsecured Notes due 2013 (the “Notes”) to prepay 100% of the aggregate principal amount of the Notes as provided in the Note Purchase Agreements governing the Notes. This amount consisted of approximately $58.4 million aggregate principal amount outstanding on the Notes, $1.1 million in accrued and unpaid interest on the Notes through the prepayment date and $3.8 million in make-whole amounts due in connection with the prepayment of the Notes. We repaid the Notes with borrowings under the Revolver.

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

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General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to us and our subsidiaries. When allocating general corporate expenses, consideration is given to property and equipment, payroll and general corporate overhead. Any direct costs are paid by us. Total corporate administrative expenses charged to us and our subsidiaries totaled $1.5 million and $1.4 million for the three months ended September 30, 2008 and 2007 and $4.6 million and $4.0 million for the nine months ended September 30, 2008 and 2007. These costs are reflected in general and administrative expenses in our condensed consolidated statements of income. At least annually, our management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, our management believes that the allocation methodologies used are reasonable.

Accounts Payable—Affiliate

Amounts payable to related parties totaled $15.9 million and $2.4 million as of September 30, 2008 and December 31, 2007. The increase in the balance in the nine months ended September 30, 2008 is due primarily to amounts due to a wholly owned subsidiary of Penn Virginia, Penn Virginia Oil & Gas, L.P. (“PVOG”), related to the natural gas gathering and processing agreement between PVR East Texas Gas Processing, LLC (“PVR East Texas”) and PVOG. See “– Gathering and Processing Revenues.” These balances are included in accounts payable on our condensed consolidated balance sheets.

Marketing Revenues

PVOG and Connect Energy Services, LLC (“Connect Energy”), our wholly owned subsidiary, are parties to a Master Services Agreement effective September 1, 2006. Pursuant to the Master Services Agreement, PVOG and Connect Energy have agreed that Connect Energy will market all of PVOG’s oil and gas production in Arkansas, Louisiana, Oklahoma and Texas for a fee equal to 1% of the net sales price (subject to specified limitations) received by PVOG for such production. The Master Services Agreement has a primary term of five years and automatically renews for additional one-year terms until terminated by either party. Under the Master Services Agreement, PVOG paid fees to Connect Energy of $1.0 million and $0.4 million for the three months ended September 30, 2008 and 2007 and $2.5 million and $1.4 million for the nine months ended September 30, 2008 and 2007. Marketing revenues are included in other revenues on our condensed consolidated statements of income.

Gathering and Processing Revenues

PVR East Texas and PVOG are parties to a natural gas gathering and processing agreement effective during the first quarter of 2008. PVR East Texas will gather and process the natural gas delivered by PVOG. Connect Energy will purchase the processed gas and plant products (NGLs) from PVOG and sell them to third parties. PVOG paid PVR East Texas $0.7 million and $1.4 million in the three and nine months ended September 30, 2008 for gathering and processing fees. These gathering and processing revenues are recorded in the natural gas midstream line on our condensed consolidated statements of income. Connect Energy purchased processed gas and plant products from PVOG for $55.7 million and $105.5 million in the three and nine months ended September 30, 2008.

Purchase of PVG Units

In July 2008, we acquired natural gas midstream assets in the Fort Worth Basin in North Texas. Part of the consideration given by us in this transaction was 2,009,995 PVG common units, which we purchased from two subsidiaries of Penn Virginia for $61.8 million. See Note 3 – Acquisitions.

We recognized a total of $0.8 million and $0.7 million for the three months ended September 30, 2008 and 2007 and $2.4 million and $1.8 million for the nine months ended September 30, 2008 and 2007 of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan. During the

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nine months ended September 30, 2008, our general partner granted 134,551 restricted units with a weighted average grant date fair value of $26.87 per unit to employees of Penn Virginia and its affiliates. During the same period, 70,007 restricted units with a weighted average grant date fair value of $27.27 per unit vested. The restricted units granted in 2008 vest over a three-year period, with one-third vesting in each year. We recognize compensation expense on a straight-line basis over the vesting period.

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. The following table sets forth the components of comprehensive income for the three and nine months ended September 30, 2008 and 2007:

Legal

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

Environmental Compliance

Our operations and those of our lessees are subject to environmental laws and regulations adopted by various governmental authorities in the jurisdictions in which these operations are conducted. The terms of our coal property leases impose liability on the relevant lessees for all environmental and reclamation liabilities arising under those laws and regulations. The lessees are bonded and have indemnified us against any and all future environmental liabilities. We regularly visit our coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Our management believes that our operations and those of our lessees comply with existing laws and regulations and does not expect any material impact on our financial condition or results of operations.

As of September 30, 2008 and December 31, 2007, our environmental liabilities included $1.2 million and $1.5 million, which represents our best estimate of the liabilities as of those dates related to our coal and natural resource management and natural gas midstream businesses. We have reclamation bonding requirements with respect to certain unleased and inactive properties. Given the uncertainty of when a reclamation area will meet regulatory standards, a change in this estimate could occur in the future.

Mine Health and Safety Laws

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

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

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financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal and natural resource management operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:

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