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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, 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):

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

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

INDEX

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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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

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

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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.

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PENN VIRGINIA RESOURCE PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Unaudited

September 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 substantially all of the proceeds from the offering to purchase newly issued common and 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, as amended, 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

Our 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 (“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 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 nine months ended September 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.

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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, some of our 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 5 for further discussion of derivative activities and the discontinuation of hedge accounting.

New Accounting Standards

In September 2006, the Financial Accounting Standards Board (the “FASB”) issued FASB Staff Position (“FSP”) AUG AIR-1, Accounting for Planned Major Maintenance Activities. FSP AUG AIR-1 prohibits companies from accruing as a liability the future costs of periodic major overhauls and maintenance of plant and equipment. FSP AUG AIR-1 is effective for fiscal years beginning after December 15, 2006. We expect that the provisions of FSP AUG AIR-1 will not have a material impact on our consolidated financial statements.

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

In September 2006, the SEC published Staff Accounting Bulletin (“SAB”) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, to address quantifying the financial statement effects of misstatements. The SEC believes that registrants and auditors must quantify the effects on the current year financial statements of correcting all misstatements, including both the carryover and reversing effects of uncorrected prior year misstatements. After considering all relevant quantitative and qualitative factors, if a misstatement is material to either the income statement or the balance sheet, a registrant’s financial statements must be adjusted. SAB No. 108 is effective for fiscal years ending after November 15, 2006. We expect that adoption of the provisions of SAB No. 108 will not have a material impact on our consolidated financial statements.

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 Boone, Logan 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 gathering 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.

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4. Equity Investments

In July 2004, we acquired from affiliates of Massey Energy Company (“Massey”) a 50 percent 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 September 30, 2006, our equity investment totaled $25.0 million, which exceeded our portion of the underlying equity in net assets by $9.2 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 of $1.0 million and $0.8 million during the nine months ended September 30, 2006 and 2005, with a corresponding increase in the investment. Cash distributions of approximately $2.7 million and $2.3 million received from the joint venture during the nine months ended September 30, 2006 and 2005, reduced the investment. Equity earnings are included in coal services revenues on our consolidated statements of income.

5. Derivative Instruments

Discontinuation of Hedge Accounting

As a result of price volatility resulting from the 2005 hurricane season, natural gas derivatives and a large portion of our natural gas liquid (“NGL”) derivatives no longer qualified for hedge accounting. Because of this non-qualification and to increase clarity in our consolidated financial statements (see below for further discussions), we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives beginning May 1, 2006. Consequently, from that date forward, we began recognizing mark-to-market gains and losses in earnings currently, rather than deferring such amounts in accumulated other comprehensive income (partners’ capital). The net mark-to-market loss on our outstanding derivatives at April 30, 2006, which was included in accumulated other comprehensive income, will be reported in our future earnings through 2008 as the original hedged transactions occur. This change in reporting will have no impact on our reported cash flows, although our future results of operations will be affected by 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.

The fair values of our derivative agreements are determined based on forward price quotes and regression analysis for the respective commodities as of September 30, 2006. The following table sets forth our positions as of September 30, 2006 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 September 30, 2006, we reported (i) a net derivative liability related to the natural gas midstream segment of $16.6 million, (ii) a loss in accumulated other comprehensive income of $10.8 million and (iii) a net loss on derivatives for hedge ineffectiveness of zero and $0.1 million for the three months and nine months ended September 30, 2006 related to derivatives in the natural gas midstream segment. The following table summarizes the effects of commodity derivative activities on our consolidated statements of income (in thousands):

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At the time we entered into our natural gas derivatives and certain 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. As discussed above, beginning May 1, 2006, we elected to discontinue hedge accounting prospectively for our remaining and future commodity derivatives.

In November 2005, we entered into a basis swap for the period January 2006 through July 2006. The basis swap related to purchases of natural gas in the Texas/Oklahoma Basin region. During the three months and nine months ended September 30, 2006, we recognized mark-to-market gains of zero and $0.7 million related to the basis swap. In accordance with SFAS No. 133, changes in market value of the derivative instrument were charged to earnings. Mark-to-market gains were recorded in the derivatives line in the other income (expense) section of our consolidated statements of income.

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 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 $1.4 million at September 30, 2006 and (ii) a gain in accumulated other comprehensive income of $1.4 million at September 30, 2006 related to the Revolver Swaps. In connection with periodic settlements, we recognized $0.2 million and $0.3 million in net hedging gains in interest expense for the three months and nine months ended September 30, 2006.

6. 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.

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Conversion of Subordinated Units

On September 30, 2006, the subordination period ended. All outstanding subordinated units will convert to common units on November 14, 2006, when the quarterly distribution will be paid. At the time of conversion, subordinated units will convert into common units on a one-for-one basis.

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 percentage ownership in the Partnership. Emerging Issues Task Force (“EITF”) Issue No. 03-6, Participating Securities and the Two-Class Method under FASB Statement No. 128, addresses the computation of earnings per share by entities that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the entity when, and if, it declares dividends on its common stock. EITF Issue No. 03-6 provides that in any accounting period where our net income exceeds our distribution for such period, we are required to present earnings per unit as if all of the earnings for the period were distributed, regardless of the pro forma nature of this allocation and whether those earnings would actually be distributed during a particular period from an economic or practical perspective. EITF Issue No. 03-6 does not impact our actual distributions for any period, but it can have the impact of reducing the earnings per limited partner unit. This result occurs as a larger portion of our earnings, as if distributed, is allocated to the incentive distribution rights held by our general partner, even though we make cash distributions on the basis of cash available for distributions, not earnings, in any given accounting period. In accounting periods where net income does not exceed our distributions for such period, EITF Issue No. 03-6 does not have any impact on our earnings per unit calculation. Basic and diluted net income per limited partner unit for the three months ended September 30, 2005 has been corrected from $0.51 to $0.44 to comply with the provisions of EITF Issue No. 03-6. A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows (in thousands, except per unit data):

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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 nine months ended September 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 and $0.375 per unit in August 2006. In October 2006, we announced a $0.40 per unit quarterly distribution for the three months ended September 30, 2006, or $1.60 per unit on an annualized basis. The distribution will be paid on November 14, 2006 to unitholders of record at the close of business on November 3, 2006.

7. 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 September 30, 2006 and 2005 and $3.7 million and $1.4 million for the nine months ended September 30, 2006 and 2005. These costs are reflected in general and administrative expenses in our 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 methods used are reasonable.

Accounts Payable—Affiliate

Amounts payable to related parties totaled $2.0 million as of September 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 our consolidated balance sheets.

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Marketing Revenues

Connect Energy Services, LLC, a wholly-owned subsidiary of the Partnership, earned $0.1 million in fees for marketing a portion of Penn Virginia Oil & Gas, L.P.’s natural gas production during the three months and nine months ended September 30, 2006. 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 consolidated statements of income.

8. Comprehensive Income

Comprehensive income represents certain changes in partners’ capital during the reporting period, including net income and charges directly to partners’ capital which are excluded from net income. Accumulated other comprehensive loss was $9.3 million at September 30, 2006. For the three months and nine months ended September 30, 2006 and 2005, the components of comprehensive income were as follows (in thousands):

9. Commitments and Contingencies

Legal

We are involved, from time to time, in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, 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.

As of September 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.

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10. Segment Information

Segment information has been prepared in accordance with SFAS No. 131, Disclosure about Segments of an Enterprise and Related Information. Under SFAS No. 131, operating segments are defined as components of an enterprise about which separate financial information is available and is evaluated regularly by the chief operating decision maker, or decision-making group, in assessing performance. Our chief operating decision-making group consists of our Chief Executive Officer and other senior officers. This group routinely reviews and makes operating and resource allocation decisions among our coal 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 (in thousands):

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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”) and its subsidiaries 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.

Coal Segment

Our coal segment includes management and leasing of coal properties and subsequent collection of royalties; other land management activities such as selling standing timber and real estate rentals; leasing of fee-based infrastructure facilities to certain lessees for coal handling, transportation and processing; and investment in a joint venture which primarily provides coal handling facilities to end-user industrial plants.

We enter into leases with various third-party operators for the right to mine coal reserves on our properties in exchange for royalty payments. We do not operate any mines. 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. In addition to coal royalty revenues, we generate coal services revenues from fees charged to lessees for the use of coal preparation and loading facilities, 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”). We also earn revenues from oil and gas royalty interests, coal transportation (“wheelage”) rights and the sale of standing timber on our properties.

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. See Item 1A, “Risk Factors.”

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Natural Gas Midstream Segment

We purchased our natural gas midstream business on March 3, 2005. The results of operations of the natural gas midstream segment since that date are included in the operations and financial summary table below.

Our natural gas midstream segment derives revenues primarily from natural gas processing contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. 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.

Acquisitions and Investments

Strategy

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.

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 Boone, Logan and Wyoming Counties, West Virginia (the “Huff Creek Acquisition”). The purchase price was $65.0 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 gathering 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.

Coal Infrastructure Construction

In September 2006, we completed construction of a new 600-ton per hour coal processing plant and rail loading facility for one of our lessees located in Knott County in eastern Kentucky. The facility began operations in October 2006. Since acquiring fee ownership and lease rights to the property’s coal reserves in July 2005, we made cumulative capital expenditures of $15.4 million related to the construction of the facility.

Current Performance

Operating income for the nine months ended September 30, 2006 was $77.4 million. The coal segment contributed $55.1 million, or 71 percent, to operating income, and the natural gas midstream segment contributed $22.3 million, or 29 percent. The following table presents a summary of certain financial information relating to our segments (in thousands):

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Coal Segment

In the nine months ended September 30, 2006, coal royalty revenues increased 20 percent, or $12.4 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 22.5 million tons in the nine months ended September 30, 2005 to 24.5 million tons in the nine months ended September 30, 2006, and our average gross royalties per ton increased from $2.71 in the nine months ended September 30, 2005 to $3.00 in the nine months ended September 30, 2006. The Illinois Basin coal reserves that we acquired in July 2005 resulted in $3.7 million of coal royalty revenues in the nine months ended September 30, 2006. The May 2006 Huff Creek Acquisition resulted in $3.4 million of coal royalty revenues in the nine months ended September 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.

Coal services revenues increased to $4.3 million in the nine months ended September 30, 2006 from $3.9 million in the nine months ended September 30, 2005. 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.

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

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