Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2006

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):

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 July 31, 2006, 33,994,650 common and 7,649,880 subordinated limited partner units were outstanding.

Table of Contents

PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1 Financial Statements

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME – unaudited

(in thousands, except per unit data)

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

1

Table of Contents

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

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

2

Table of Contents

PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS - Unaudited

(in thousands)

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

3

Table of Contents

PENN VIRGINIA RESOURCE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS – Unaudited

June 30, 2006

1. Nature of Operations

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. Since the acquisition of a natural gas midstream business in March 2005, 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.

We purchased our natural gas midstream business on March 3, 2005, through the acquisition of Cantera Gas Resources, LLC (the “Cantera Acquisition”). As a result of the Cantera Acquisition, 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.

The general partner of the Partnership is Penn Virginia Resource GP, LLC, a wholly owned subsidiary of Penn Virginia. Penn Virginia recently formed Penn Virginia GP Holdings, L.P. (“GP Holdings”), a Delaware limited partnership. GP Holdings filed a Registration Statement on Form S-1 in July 2006 with the intent of completing an initial public offering of common units. GP Holdings was formed to own the general partner interest, all of the incentive distribution rights, 7,475,414 common units and 7,649,880 subordinated units in the Partnership. If the offering is completed, GP Holdings will use the proceeds from the offering to purchase newly issued class B common units from us, and we expect to use the proceeds from such purchase to repay debt outstanding under our revolving credit facility. The initial public offering of GP Holdings common units is not guaranteed to occur. Please refer to GP Holdings’ Registration Statement on Form S-1 for more information on the potential initial public offering of GP Holdings common units.

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, 2005, except as discussed below. Please refer to such Form 10-K for a further discussion of those policies.

Basis of Presentation

The accompanying unaudited 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 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, 2005. Operating results for the six months ended June 30, 2006, are not necessarily indicative of the results that may be expected for the year ending December 31, 2006. Certain reclassifications have been made to conform to the current period’s presentation.

4

Table of Contents

Derivative Activities

Prior to January 1, 2006, all of our commodity derivative contracts were accounted for using hedge accounting in accordance with Statement of Financial Accounting Standards (“SFAS”) No. 133, Accounting for Derivative Instruments and Hedging Activities. Effective January 1, 2006, our natural gas derivative contracts and certain NGL derivative contracts no longer qualified for hedge accounting. Effective May 1, 2006, we elected to discontinue hedge accounting prospectively for all remaining and future commodity derivatives. See Note 4 for further discussion of derivative activities and the discontinuation of hedge accounting.

3. Acquisitions

Huff Creek Acquisition

On May 25, 2006, we acquired from Huff Creek Energy Company and Appalachian Coal Holdings, Inc. the lease rights to approximately 69 million tons of coal reserves located on approximately 20,000 acres in Logan, Boone and Wyoming Counties, West Virginia. The purchase price was approximately $65 million and was funded with long-term debt under our revolving credit facility.

Transwestern Acquisition

On June 30, 2006, we completed the acquisition of approximately 115 miles of pipelines and related compression facilities in Texas and Oklahoma to complement our existing midstream systems (the “Transwestern Acquisition”). We paid for the acquisition with approximately $15 million in cash. In July 2006, we borrowed $15 million under our revolving credit facility to replenish the cash used in the Transwestern Acquisition.

4. Derivative Instruments

Discontinuation of Hedge Accounting

Because our natural gas derivatives and a large portion of our NGL derivatives no longer qualify for hedge accounting and to increase clarity in our 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 recognize 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. 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 oil and gas prices.

Natural Gas Midstream Segment Commodity Derivatives

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

5

Table of Contents

The fair values of our derivative agreements are determined based on forward price quotes and regression analysis for the respective commodities as of June 30, 2006. The following table sets forth our positions as of June 30, 2006, for commodities related to natural gas midstream revenues (ethane, propane and crude oil) and cost of midstream gas purchased (natural gas):

Based upon the assessment of derivative agreements at June 30, 2006, we reported (i) a net derivative liability related to the natural gas midstream segment of $30.3 million, (ii) a loss in accumulated other comprehensive income of $11.6 million and (iii) a net loss on derivatives for hedge ineffectiveness of zero and $0.1 million for the three months and six months ended June 30, 2006, related to derivatives in the natural gas midstream segment. The following table summarizes the effects of commodity derivative activities on the accompanying consolidated statements of income:

6

Table of Contents

At the time we entered into our natural gas derivatives and certain natural gas liquid (“NGL”) derivatives, physical purchase prices of natural gas correlated well with NYMEX natural gas prices and physical sales prices of NGLs correlated well with NGL index prices. However, in the second half of 2005, basis differentials for certain derivative agreements widened as NYMEX natural gas prices and NGL index prices reached historically high levels. In the first quarter of 2006, our correlation assessment indicated that our NYMEX natural gas derivatives and certain NGL derivatives could no longer be considered “highly effective” hedges under the parameters of the accounting rules. Consequently, we discontinued hedge accounting effective January 1, 2006, for our natural gas derivatives and certain NGL derivatives that were no longer considered highly effective.

In November 2005, we entered into a basis swap for the period January 2006 through July 2006. The basis swap relates to purchases of natural gas in the Texas/Oklahoma Basin region. At June 30, 2006, the fair value of the basis swap asset was less than $0.1 million. During the three months and six months ended June 30, 2006, we recognized mark-to-market gains of $0.3 million and $0.7 million related to the basis swap. We have chosen not to designate this derivative as a hedge pursuant to SFAS No. 133. Therefore, in accordance with SFAS No. 133, changes in market value of the derivative instrument are charged to earnings. Mark-to-market gains are recorded in the derivatives line in the other income (expense) section of the accompanying consolidated statements of income.

Interest Rate Swaps

In September 2005, we entered into interest rate swap agreements to establish fixed rates on $60 million of the LIBOR-based portion of the outstanding balance on our revolving credit facility until March 2010 (the “Revolver Swaps”). We pay a weighted average fixed rate of 4.22 percent 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 $2.7 million at June 30, 2006, and (ii) a gain in accumulated other comprehensive income of $2.7 million at June 30, 2006, related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.1 million and $0.2 million in net hedging gains in interest expense for the three months and six months ended June 30, 2006.

7

Table of Contents

5. Partners’ Capital and Distributions

Unit Split

On February 23, 2006, the board of directors of our general partner declared a two-for-one split of our common and subordinated units. To effect the split, we distributed one additional common unit and one additional subordinated unit (a total of 16,997,325 common units and 3,824,940 subordinated units) on April 4, 2006, for each common unit and subordinated unit held of record at the close of business on March 28, 2006. All units and per unit data have been retroactively adjusted to reflect the unit split.

Net Income per Limited Partner Unit

Net income per limited partner unit is based on the weighted average number of common and subordinated units outstanding during the period and is allocated in the same ratio as quarterly cash distributions are made. Net income per limited partner unit is computed by dividing the limited partners’ interest in net income, after deducting our general partner’s two percent interest and incentive distributions, by the weighted average number of limited partner units outstanding.

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, 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 during the six months ended June 30, 2006 and 2005 (in thousands, except per unit information):

We paid quarterly distributions of $0.35 per unit in February 2006 and May 2006. In July 2006, we announced a $0.375 per unit distribution for the three months ended June 30, 2006, or $1.50 per unit on an annualized basis. The distribution will be paid on August 14, 2006, to unitholders of record at the close of business on August 4, 2006.

8

Table of Contents

6. Related Party Transactions

General and Administrative

Penn Virginia charges us for certain corporate administrative expenses which are allocable to its 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 $0.5 million for the three months ended June 30, 2006 and 2005, and $2.7 million and $0.9 million for the six months ended June 30, 2006 and 2005. These costs are reflected in general and administrative expenses in the accompanying 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 $2.3 million as of June 30, 2006. This balance consists primarily of amounts due to our general partner for general and administrative expenses incurred on our behalf and is included in accounts payable on the accompanying consolidated balance sheets.

7. Comprehensive Income

Comprehensive income represents changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. Accumulated other comprehensive loss was $8.9 million at June 30, 2006. For the three months and six months ended June 30, 2006 and 2005, the components of comprehensive income were as follows (in thousands):

8. 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, 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. These 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.

9

Table of Contents

As of June 30, 2006, our environmental liabilities were $2.4 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.

9. 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 officials. 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:

Coal

The coal segment includes:

Natural Gas Midstream

The natural gas midstream segment 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.

10

Table of Contents

Segment Financial Information

The following table presents a summary of certain financial information relating to our segments (in thousands):

11

Table of Contents

12

Table of Contents

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

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 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. Penn Virginia contributed its coal properties and related assets to us and, effective with the closing of our initial public offering in October 2001, our common units began trading publicly on the New York Stock Exchange under the symbol “PVR.”

Both in our current limited partnership form and our previous corporate form, we have managed coal properties since 1882. Since the acquisition of a natural gas midstream business in March 2005, we conduct operations in two business segments: coal and natural gas midstream. A description of each of our reportable segments follows:

We continually evaluate acquisition opportunities that are accretive to cash available for distribution to our unitholders. These opportunities include, but are not limited to, acquiring additional coal properties and reserves and acquiring or constructing assets for coal services and natural gas midstream gathering and processing, all of which would provide a primarily fee-based revenue stream.

Acquisitions and Investments

Huff Creek Acquisition

On May 25, 2006, we acquired from Huff Creek Energy Company and Appalachian Coal Holdings, Inc. the lease rights to approximately 69 million tons of coal reserves located on approximately 20,000 acres in Logan, Boone and Wyoming Counties, West Virginia (the “Huff Creek Acquisition”). The purchase price was approximately $65 million and was funded with long-term debt under our revolving credit facility.

Transwestern Acquisition

On June 30, 2006, we completed the acquisition of approximately 115 miles of pipelines and related compression facilities in Texas and Oklahoma to complement our existing midstream systems (the “Transwestern Acquisition”). We paid for the acquisition with approximately $15 million in cash. In July 2006, we borrowed $15 million under our revolving credit facility to replenish the cash used in the Transwestern Acquisition.

13

Table of Contents

Coal Infrastructure Construction

We expect to complete construction and commence operation of a new 600-ton per hour coal processing plant and rail loading facility in the third quarter of 2006 for one of our lessees located in Knott County in eastern Kentucky. Since acquiring fee ownership and lease rights to the property’s coal reserves in July 2005, we made cumulative capital expenditures of $7.7 million related to the construction of the facility as of June 30, 2006. Total capital expenditures for the construction are expected to be approximately $15 million.

Current Performance

Operating income for the six months ended June 30, 2006 was $47.9 million. The coal segment contributed $36.7 million, or 77 percent, to operating income, and the natural gas midstream segment contributed $11.2 million, or 23 percent. The following table presents a summary of certain financial information relating to our segments (in thousands):

Coal Segment

In the six months ended June 30, 2006, coal royalty revenues increased 22 percent, or $8.5 million, over the same period last year due to acquisitions, more coal being mined by our lessees and increasing coal prices. Tons produced by our lessees increased from 14.0 million tons in the six months ended June 30, 2005 to 15.7 million tons in the six months ended June 30, 2006, and our average gross royalties per ton increased from $2.73 in the six months ended June 30, 2005 to $2.98 in the six months ended June 30, 2006. The Illinois Basin coal reserves that we acquired in July 2005 resulted in $2.6 million of coal royalty revenues in the six months ended June 30, 2006. Generally, as coal prices increase, our average royalties per ton also increase because the vast majority of our lessees pay royalties based on the gross sales prices of the coal mined.

In managing our properties, we actively work with our lessees to develop efficient methods to exploit our reserves and to maximize production from our properties. We earn revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their 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 Energy Company (“Massey”). Coal services revenues increased to $2.8 million in the six months ended June 30, 2006, from $2.6 million in the six months ended June 30, 2005. We believe that these types of fee-based infrastructure assets provide good investment and cash flow opportunities for us, and we continue to look for additional investments of this type, as well as other primarily fee-based assets. We also earn revenues from oil and gas royalty interests, coal transportation (“wheelage”) rights and the sale of standing timber on our properties.

14

Table of Contents

As of June 30, 2006, our primary coal reserves and coal infrastructure assets were located on the following properties:

Natural Gas Midstream Segment

The gross processing margin for our natural gas midstream operations increased from $16.9 million in the six months ended June 30, 2005 to $30.2 million in the six months ended June 30, 2006. This increase was due primarily to higher NGL prices. Inlet volumes at our gas processing plants and gathering systems were 137 million cubic feet (“MMcf”) per day in the six months ended June 30, 2006, an increase over 126 MMcf per day in the six months ended June 30, 2005, primarily due to additional well connections in the area. As part of our risk management strategy, we use derivative financial instruments to hedge NGLs sold and natural gas purchased.

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.

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

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 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. Approximately 39 percent of natural gas midstream revenues for the six months ended June 30, 2006, related to three customers.

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.

15

Table of Contents

Derivative Instruments and Hedging 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 in our 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 occurs. The results reflected in the statement of income are based on the actual settlements with the counterparty. We include this gain or loss in natural gas midstream revenues or cost of midstream gas purchased, depending on the commodity. Effective January 1, 2006, some of our derivatives did not qualify for hedge accounting under SFAS No. 133, and changes in market value of these derivative instruments were recognized in earnings. When we do not use hedge accounting, we could experience significant changes in the estimate of derivative gain or loss recognized in revenue 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.

Because our natural gas derivatives and a large portion of our NGL derivatives no longer qualify for hedge accounting and to increase clarity in our 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 recognize 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. 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 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 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.

Liquidity and Capital Resources

Since the closing of our initial public offering in October 2001, cash generated from operations and our borrowing capacity, supplemented by proceeds from the issuance of new common units, have been sufficient to meet our scheduled distributions, scheduled debt payments, working capital requirements and capital expenditures. Our primary cash requirements consist of quarterly distributions to our general partner and unitholders, normal operating expenses, interest and principal payments on our long-term debt and acquisitions of new assets or businesses. Summarized cash flow statements for the six months ended June 30, 2006 and 2005, consolidating our segments are set forth below (in millions):

16

Table of Contents