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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2007

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)

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 May 1, 2007, 42,060,974 common and 4,045,311 Class B limited partner units were outstanding.

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

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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

(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

March 31, 2007

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 conduct operations in two business segments: coal and natural gas midstream.

In our coal segment, we do not operate any mines. Instead, we enter into leases with various third-party operators which give those operators the right to mine coal reserves on our land in exchange for royalty payments. We also provide fee-based infrastructure facilities to some of our lessees and third parties to generate coal services revenues. These facilities include coal loading facilities, preparation plants and coal handling facilities located at end-user industrial plants. We also sell timber growing on our land.

In our natural gas midstream segment, we own and operate a significant set of midstream assets. 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.

Our general partner is Penn Virginia Resource GP, LLC (“PVG”), which is a wholly owned subsidiary of Penn Virginia GP Holdings, L.P. 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 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, 2006. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

The condensed consolidated financial statements include the accounts of the Partnership and all wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. The 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 the condensed consolidated financial statements have been included. These financial statements should be read in conjunction with our consolidated financial statements and footnotes included in our Annual Report on Form 10-K for the year ended December 31, 2006. Operating results for the three months ended March 31, 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 February 2007, the Financial Accounting Standards Board (the “FASB”) issued Statement of Financial Accounting Standard (“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 have not yet determined the impact on our financial statements of adopting SFAS No. 159 effective January 1, 2008.

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In July 2004, we acquired from affiliates of Massey Energy Company (“Massey”) a 50% interest in Coal Handling Solutions, LLC, a joint venture formed to own and operate end-user coal handling facilities. We account for the investment under the equity method of accounting. In 2004, the original cash investment of $28.4 million was capitalized. At March 31, 2007, our equity investment totaled $25.5 million, which exceeded our portion of the underlying equity in net assets by $8.2 million. The difference is being amortized to equity earnings over the life of coal services contracts in place at the time of the acquisition. In accordance with the equity method, we recognized equity earnings in the three months ended March 31, 2007 and 2006 of $0.2 million and $0.3 million, with a corresponding increase in the investment. The joint venture generally pays to us quarterly distributions of our portion of the joint venture’s operating cash flows. We received no cash distributions from the joint venture in the three months ended March 31, 2007 or 2006. Equity earnings are included in coal services revenues on our condensed consolidated statements of income.

Natural Gas Midstream Segment Commodity Derivatives

We utilize swap derivative contracts to hedge against the variability in cash flows associated with forecasted natural gas midstream revenues and cost of 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.

The fair values of our derivative agreements are determined based on forward price quotes and regression analysis for the respective commodities as of March 31, 2007. The following table sets forth our positions as of March 31, 2007 for commodities related to natural gas midstream revenues (ethane, propane and crude oil) and cost of midstream gas purchased (natural gas):

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Based upon our assessment of derivative agreements at March 31, 2007, we reported (i) a net derivative liability related to the natural gas midstream segment of $12.7 million, (ii) a loss in accumulated other comprehensive income of $9.2 million related to derivatives in the natural gas midstream segment for which we discontinued cash flow hedge accounting in 2006. The following table summarizes the effects of commodity derivative activities on our condensed consolidated statements of income:

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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 $1.1 million at March 31, 2007 and (ii) a gain in accumulated other comprehensive income of $1.1 million at March 31, 2007 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.2 million in net hedging gains in interest expense for the year ended March 31, 2007.

As of March 31, 2007, partners’ capital consisted of 42.1 million common units, representing a 89% limited partner interest, 4.0 million Class B units, representing a 9% limited partner interest, and a 2% general partner interest. As of March 31, 2007, affiliates of Penn Virginia owned, in the aggregate, a 44% interest in us, consisting of 15.9 million common units, 4.0 million Class B units and a 2% general partner interest.

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.

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:

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The following table reflects the allocation of total cash distributions paid during the three months ended March 31, 2007 and 2006:

We paid a quarterly distribution of $0.40 per unit in February 2007. In April 2007, we announced a $0.41 per unit distribution for the three months ended March 31, 2007, or $1.64 per unit on an annualized basis. The distribution will be paid on May 15, 2007 to unitholders of record at the close of business on May 4, 2007.

Sale of Units to PVG

We sold 33,147 newly issued Class B units to PVG in January 2007 for $25.45 per Class B unit, which was the same price as the Class B units we sold to PVG in December 2006. PVG paid us an aggregate of $0.9 million for the purchase of the Class B units and to maintain its 2% general partner interest in us.

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 $1.1 million and $1.6 million for the three months ended March 31, 2007 and 2006. These costs are reflected in general and administrative expenses in our condensed consolidated statements of income. At least annually, management performs an analysis of general corporate expenses based on time allocations of shared employees and other pertinent factors. Based on this analysis, management believes the allocation methodologies used are reasonable.

Accounts Payable—Affiliate

Amounts payable to related parties totaled $2.7 million as of March 31, 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 the Partnership, earned $0.4 million in fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during the three months ended March 31, 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.

For the three months ended March 31, 2007 and 2006, we recognized a total of $0.5 million and $0.5 million of compensation expense related to the granting of common units and deferred common units and the vesting of restricted units granted under the long-term incentive plan. During the three months ended March 31, 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. During the same period, 42,582 restricted units with a weighted average grant date fair value $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.

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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. For the three months ended March 31, 2007 and 2006, the components of comprehensive income were as follows:

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, management believes these claims will not have a material effect on our financial position, liquidity or operations.

Environmental Compliance

The operations of our coal lessees and our natural gas midstream segment 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 coal properties to monitor lessee compliance with environmental laws and regulations and to review mining activities. Management believes that the operations of our coal lessees and our natural gas midstream segment comply with existing regulations and does not expect any material impact on our financial condition or results of operations.

As of March 31, 2007, environmental liabilities included $1.6 million, which represents our best estimate of our liabilities as of that date related to our coal 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 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 the Chief Executive Officer and other senior officers.

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This group routinely reviews and makes operating and resource allocation decisions among our coal operations and our natural gas midstream operations. Accordingly, our reportable segments are as follows:

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

Subsequent to March 31, 2007, we entered into five commodity derivative agreements. Four of the derivative agreements are costless collar contracts utilized to mitigate commodity price exposure related to our percent-of-proceeds contracts. The following table summarizes the terms of these positions:

The fifth commodity derivative agreement entered into subsequent to March 31, 2007 is a swap derivative contract utilized to mitigate frac spread exposure related to our wellhead purchase contracts. This derivative contract consists of an agreement to sell natural gas liquids forward at a predetermined swap price and to purchase an equivalent volume of natural gas forward on an MMBtu basis. The following table summarizes the terms of the contract:

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The following review 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

We are a publicly traded Delaware limited partnership formed by Penn Virginia Corporation (“Penn Virginia”) in 2001 that is principally engaged in the management of coal 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: coal and natural gas midstream. In the three months ended March 31, 2007, approximately 80%, or $17.9 million, of our operating income was attributable to our coal segment, and approximately 20%, or $4.4 million, of our operating income was attributable to our natural gas midstream segment.

Coal 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 do not operate any mines. In the three months ended March 31, 2007, our lessees produced 8.3 million tons of coal from our properties and paid us coal royalty revenues of $25.0 million, for an average gross coal royalty per ton of $3.02. Approximately 81% of our coal royalty revenues in the three months ended March 31, 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 royalty 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. The possibility exists that new legislation or regulations have 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.

Coal prices also impact coal royalty revenues. Coal prices, especially in Central Appalachia where the majority of our coal is produced, increased significantly from the beginning of 2004 through most of 2006. The price increase during that period was primarily the result of increased electricity demand, rebuilding of inventories and decreasing coal production in Central Appalachia. In the second half of 2006 and continuing into 2007, coal prices decreased from the historically high levels experienced in the previous two and one half years, due to higher than normal coal inventories at electric utilities and milder than normal winter weather.

Substantially all of our leases require the lessee to pay minimum rental payments to us in monthly or annual installments. We actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We also earn revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their

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production levels and generate additional coal royalty revenues, and from industrial third party coal end-users by owning and operating coal handling facilities through our joint venture with Massey. In addition, we earn revenues from oil and gas royalty interests we own, from coal transportation 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.

Natural Gas Midstream Segment

We own and operate midstream assets that include approximately 3,631 miles of natural gas gathering pipelines and three natural gas processing facilities located in Oklahoma and the panhandle of Texas, which have 160 million cubic feet per day (“MMcfd”) of total capacity. Our 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. We acquired our natural gas midstream assets through the acquisition of Cantera Gas Resources, LLC in March 2005. We believe that this acquisition established a platform for future growth in the natural gas midstream sector and diversified our cash flows into another long-lived asset base. Since acquiring these assets, we have expanded our natural gas midstream business by adding 181 miles of new gathering lines.

For the three months ended March 31, 2007, throughput volumes at our gas processing plants and gathering systems were 15.9 billion cubic feet (“Bcf”), or approximately 177 MMcfd, and three of our natural gas midstream customers accounted for 56% of our natural gas midstream revenues.

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 throughput volume. 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.

Revenues, profitability and the future rate of growth of the 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.

Current Performance

Operating income for the three months ended March 31, 2007 was $22.3 million, compared with $18.2 million for the three months ended March 31, 2006. The coal segment contributed $17.9 million, or 80%, to operating income, and the natural gas midstream segment contributed $4.4 million, or 20%. The following table presents a summary of certain financial information relating to our segments:

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Coal Segment

In the three months ended March 31, 2007, coal royalty revenues increased 11%, or $2.6 million, over the same time period in 2006 due to acquisitions and an increase in production by our lessees. Tons produced by our lessees increased from 7.7 million tons in the three months ended March 31, 2006 to 8.3 million tons in the same period of 2007, and our average gross royalties per ton increased from $2.90 in the three months ended March 31, 2006 to $3.02 in the same period in 2007. Generally, as coal prices change, our average royalties per ton also change 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 royalties occur as our lessees’ contracts are renegotiated. The coal reserves in West Virginia that we acquired in May 2006 resulted in $1.5 million of coal royalty revenues in the three months ended March 31, 2007.

Coal services revenues increased to $1.6 million in the three months ended March 31, 2007 from $1.4 million in the same period of 2006. This increase was due primarily to the completed construction of a coal service facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.4 million to coal services revenues in the three months ended March 31, 2007. We believe that these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

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

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Natural Gas Midstream Segment

The gross processing margin for our natural gas midstream operations increased from $10.5 million in the three months ended March 31, 2006 to $15.6 million in the three months ended March 31, 2007. This increase was due primarily to a stronger pricing environment for the first quarter of 2007 compared to the first quarter of 2006 with higher fractional spreads for the period. System throughput volumes at our gas processing plants and gathering systems were 177 MMcfd for the three months ended March 31, 2007, an increase of 19 MMcfd from the three months ended March 31, 2006, primarily due to higher average daily system throughput volumes resulting from the pipeline acquisition completed in the second quarter of 2006 and successful drilling of local producers. Our 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 March 31, 2007, the natural gas midstream business generated a majority of its gross margin from contractual arrangements under which its margin is exposed to increases and decreases in the price of natural gas and NGLs. As part of our risk management strategy, we use derivative financial instruments to economically hedge NGLs sold and natural gas purchased. See the tables in Note 4 in the Notes to Condensed Consolidated Financial Statements for the effects of our derivative program on gross processing margin.

Our natural gas midstream assets are primarily located in the Mid-Continent area of Oklahoma and the panhandle of Texas. The following table sets forth information regarding our natural gas midstream assets as of March 31, 2007:

Summary of Critical Accounting Policies and Estimates

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

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Natural Gas Midstream Revenues

Revenue from the sale of NGLs and residue gas is recognized when the NGLs and residue gas produced at our gas processing plants are sold. Gathering and transportation revenue is 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 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 Royalty Revenues

Coal royalty 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 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. This change in reporting 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.

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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.

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 major 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.

Summarized cash flow statements for the three months ended March 31, 2007 and 2006, consolidating our segments, are set forth below (in thousands):

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Cash Flows

Cash provided by operating activities increased $10.2 million, or 77%, to $23.5 million for the three months ended March 31, 2007 from $13.3 million for the three months ended March 31, 2006. The overall increase in cash provided by operating activities for the three months ended March 31, 2007 compared to the same period of 2006 was primarily attributable to an increase in coal royalty revenues and an overall increase in working capital.

Capital expenditures, excluding non-cash items, for the three months ended March 31, 2007 and 2006 were as follows:

Cash flows from operations funded our capital expenditures for the three months ended March 31, 2007 and 2006. Distributions to partners increased to $21.0 million in the three months ended March 31, 2007 from $15.5 million in the three months ended March 31, 2006 because we increased the quarterly unit distribution to $0.40 per unit from $0.35 per unit.

Long-Term Debt

As of March 31, 2007, we had outstanding borrowings of $223.1 million, consisting of $153.2 million borrowed under our revolving credit facility and $69.9 million of senior unsecured notes (the “Notes”). The current portion of the Notes as of March 31, 2007 was $11.8 million.

Revolving Credit Facility. As of March 31, 2007, we had $153.2 million outstanding under our $300 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 March 31, 2007. In the three months ended March 31, 2007, we incurred commitment fees of $0.1 million on the unused portion of the Revolver. We have a one-time option to expand the Revolver by $150 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders. The interest rate under the Revolver fluctuates based on our ratio of 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 financial covenants under the Revolver require us to maintain specified levels of debt to consolidated EBITDA and consolidated EBITDA to interest. The financial covenants restricted our borrowing capacity under the Revolver to approximately $273.8 million as of March 31, 2007. At the current $300 million limit on the Revolver, and given our outstanding balance of $153.2 million, net of $1.6 million of letters of credit, we could borrow up to $145.2 million without exercising our one-time option to

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expand the Revolver. In order to utilize the full extent of the $273.8 million borrowing capacity, we would need to exercise our one-time option to expand the Revolver by $150 million. 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 March 31, 2007, we were in compliance with all of our covenants under the Revolver.

Senior Unsecured Notes. As of March 31, 2007, we owed $69.9 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 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 March 31, 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 0.75% in effect as March 31, 2007, the total interest rate on the $60 million portion of Revolver borrowings covered by the Revolver Swaps was 4.97% at March 31, 2007.

Future Capital Needs and Commitments

Part of our strategy is to make acquisitions which increase cash available for distribution to our unitholders. 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. 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.

In 2007, we anticipate making capital expenditures, excluding acquisitions, of $3.6 million to $4.7 million for coal services related projects and other property and equipment and $50 to $54 million for natural gas midstream system expansion projects. We intend to fund these capital expenditures with a combination of cash flows provided by operating activities and borrowings under the Revolver, under which we had $145.2 million of borrowing capacity as of March 31, 2007. 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. Funding sources for future acquisitions are dependent on the size of any such acquisitions and are expected to be provided by a combination of cash flows provided by operating activities and borrowings, and potentially with the proceeds from the issuance of additional equity.

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.

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Results of Operations

The following table sets for a summary of certain financial data for the periods indicated:

Selected Financial Data – Consolidated

The increase in net income for the three months ended March 31, 2007 compared to the same period in 2006 was primarily attributable to a $4.1 million increase in operating income, a $3.5 million decrease in derivative losses and a decrease of $0.5 million in interest expense as a result of making a $114.6 million principal payment on our Revolver in December 2006. Operating income increased for the three months ended March 31, 2007 primarily due to a stronger pricing environment and higher system throughput volumes in the natural gas midstream segment, as well as increased coal royalty revenues resulting from higher average royalty prices per ton and production from our lessees.

Coal Segment

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

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Revenues. Coal royalty revenues increased to $25.0 million for the three months ended March 31, 2007 from $22.4 million for the same period in 2006, or 11%, due to acquisitions and increased production by our lessees. Tons produced by our lessees increased from 7.7 million tons in the three months ended March 31, 2006 to 8.3 million tons in the same period of 2007, and our average gross royalties per ton increased from $2.90 for the three months ended March 31, 2006 to $3.02 for the same period in 2007. The increase in the average royalty per ton was primarily due to a greater percentage of coal being produced from certain price-sensitive leases and, for most of 2007, stronger market conditions for coal resulting in higher prices. Generally, as coal prices change, our average royalties per ton also change 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 royalties occur as our lessees’ contracts are renegotiated. The coal reserves in West Virginia that we acquired in May 2006 resulted in $1.5 million of coal royalty revenues in the three months ended March 31, 2007.

Coal services revenues increased to $1.6 million for the three months ended March 31, 2007 from $1.4 million for the same period in 2006, or 12%, primarily due to the completed construction of a coal service facility in Knott County, Kentucky, which began operations in October 2006. This facility contributed $0.4 million to coal service revenue in the three months ended March 31, 2007. We believe these types of fee-based infrastructure assets provide good investment and cash flow opportunities, and we continue to look for additional investments of this type, as well as other primarily fee-based assets.

Expenses. Operating expenses increased to $2.2 million for the three months ended March 31, 2007 from $1.0 million for the same period in 2006, or 122%, due to production on our subleased Central Appalachian property acquired in May 2006. Fluctuations in production on subleased properties have a direct impact on royalty expense. General and administrative expenses increased by 17% to $2.6 million due to increased payroll costs and professional fees related to evaluating acquisition opportunities. Depreciation, depletion and amortization expense increased by 16% to 5.5 million due to the increase in production and a higher depletion rate on recently acquired reserves.

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Natural Gas Midstream Segment

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: