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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, 2005

Or

For the transition period from              to             

Commission File Number 1-16735

PENN VIRGINIA RESOURCE PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

(610) 687-8900

(Registrant’s Telephone Number, Including Area Code)

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report.)

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

Indicate by a check mark whether the Registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).    Yes  x    No  ¨

As of May 2, 2005, 14,875,300 common and 5,737,410 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

March 31, 2005

1. ORGANIZATION

Penn Virginia Resource Partners, L.P. (the “Partnership,” “we,” “our” or “us”), is a Delaware limited partnership formed by Penn Virginia Corporation 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 royalty, land leasing and coal services (for our lessees and third party end-users) and natural gas midstream.

In our coal royalty, land leasing and coal services 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 midstream business on March 3, 2005 through the acquisition of Cantera Gas Resources, LLC (See Note 4.). As a result of this acquisition, we own and operate a significant set of midstream assets. Our midstream business derives revenues primarily from gas processing and gas purchase 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 Corporation (“Penn Virginia”).

2. BASIS OF PRESENTATION

The accompanying unaudited consolidated financial statements include the accounts of Penn Virginia Resource Partners, L.P. and all wholly-owned subsidiaries. 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 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, 2004. Operating results for the three months ended March 31, 2005, are not necessarily indicative of the results that may be expected for the year ended December 31, 2005. Certain reclassifications have been made to conform to the current period’s presentation.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Accounting polices are consistent with those described in our Annual Report on Form 10-K for the year ended December 31, 2004, except as discussed below. Please refer to such Form 10-K for a further discussion of those policies.

Natural Gas Midstream Revenues

Revenues from the sale of natural gas liquids (“NGLs”) and residue gas is recognized when the NGLs and residue gas produced at our gas processing plants are sold. Gathering and transportation revenues are recognized based upon actual volumes delivered. Because it takes time to gather information from various purchasers and measurement locations and to 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. Since the settlement process may take up to 30 days following the month of actual production, our financial results include estimates of production and revenues for the period of actual production. Any differences, which are not expected to be significant, between the actual amounts ultimately received or paid and the original estimates are recorded in the period they become finalized.

Goodwill

We had approximately $8.0 million of goodwill at March 31, 2005, based on the preliminary purchase price allocation for the Cantera Acquisition (as defined in Note 4). This amount may change based on the final purchase

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price allocation. The goodwill has been allocated to the midstream segment. In accordance with Statement of Financial Accounting Standards (“SFAS”) No. 142, Goodwill and Other Intangible Assets, goodwill will be assessed at least annually for impairment. We intend to test goodwill for impairment during the fourth quarter of our fiscal year.

Intangibles

Intangible assets at March 31, 2005, included $35.5 million for customer contracts and relationships and $4.6 million for rights of way. These amounts may change based on the final purchase price allocation as described in Note 4. Customer contracts and relationships are amortized on a straight-line basis over the expected useful lives of the individual contracts and relationships, which do not exceed 15 years. Rights of way are amortized on a straight-line basis over a period of 15 years. Total intangible amortization was approximately $0.4 million during the quarter ended March 31, 2005. There were no intangible assets or related amortization in 2004. As of March 31, 2005, accumulated amortization of intangible assets was $0.4 million.

Aggregate amortization expense for the year ending December 31, 2005, is estimated to be approximately $4.1 million. The following table summarizes our estimated aggregate amortization expense for the next five years (in thousands):

4. ACQUISITION OF NATURAL GAS MIDSTREAM BUSINESS

On March 3, 2005, we completed our acquisition (the “Cantera Acquisition”) of Cantera Gas Resources, LLC (“Cantera”), a midstream gas gathering and processing company with primary locations in the mid-continent area of Oklahoma and the panhandle of Texas. The midstream business operates as PVR Midstream LLC, a subsidiary of Penn Virginia Operating Co. LLC, which is a wholly owned subsidiary of the Partnership. As a result of the Cantera Acquisition, we own and operate a significant set of midstream assets that include approximately 3,400 miles of gas gathering pipelines and three natural gas processing facilities, which have 160 million cubic feet per day (MMcfd) of total capacity. Our midstream business derives revenues primarily from gas processing and gas purchase contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We believe the Cantera Acquisition will establish a platform for future growth in the natural gas midstream sector and will diversify our cash flows into another long-lived asset base. The results of operations of PVR Midstream LLC since March 3, 2005, the closing date of the Cantera Acquisition, are included in the accompanying consolidated statements of income.

Total cash paid for the Cantera Acquisition was approximately $196 million, which we funded with a $110 million term loan and with borrowings under our revolving credit facility. The purchase price allocation for the Cantera Acquisition has not been finalized because we are still in the process of settling various post-closing adjustments with the seller and obtaining final appraisals of assets acquired and liabilities assumed. We used proceeds of $127.7 million from our sale of common units in a subsequent public offering in March 2005 to repay our term loan in full and to reduce outstanding indebtedness under our revolving credit facility. The total purchase price was allocated to the assets purchased and the liabilities assumed in the Cantera Acquisition based upon preliminary fair values on the date of acquisition, as follows (in thousands):

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The preliminary purchase price allocation includes approximately $8.0 million of goodwill. The significant factors that contributed to the recognition of goodwill include entering into the natural gas midstream business and the ability to acquire an established business with an assembled workforce. 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 rather is tested for impairment at least annually. Accordingly, the unaudited pro forma financial information presented below does not include amortization of the goodwill recorded in the acquisition.

The preliminary purchase price allocation includes approximately $40.1 million of intangible assets that are primarily associated with assumed customer contracts, customer relationships and rights of way. These intangible assets are being amortized over periods of up to 15 years, the period in which benefits are derived from the contracts and relationships assumed, and will be reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

The following unaudited pro forma financial information reflects the consolidated results of operations of the Partnership as if the Cantera Acquisition, the closing of the amended credit facility and the public offering of common units had occurred on January 1 of the reported period. The pro forma information includes primarily adjustments for depreciation of acquired property and equipment, amortization of intangibles, interest expense for acquisition debt and the change in weighted average common units resulting from the public offering. The pro forma financial information is not necessarily indicative of the results of operations as it would have been had these transactions been effected on the assumed date.

5. ASSET RETIREMENT OBLIGATION

We account for asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. SFAS No. 143 applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of such assets.

The fair value of a liability for an asset retirement obligation is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. The fair value of the liability is also added to the carrying amount of the associated asset and is depreciated over the life of the asset. The liability is accreted through charges to accretion expense, which are recorded as additional depreciation, depletion and amortization. If the obligation is settled for other than the carrying amount of the liability, a gain or loss on settlement will be recognized.

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Below is a reconciliation of the beginning and ending aggregate carrying amount of our asset retirement obligations, which are included in other liabilities on the accompanying consolidated balance sheets as of March 31, 2005 (in thousands).

6. HEDGING ACTIVITIES

Commodity Cash Flow Hedges

When we agreed to acquire the midstream business from Cantera, one of our objectives was to support the economics of that acquisition. We achieved this objective by entering into pre-closing commodity price hedging agreements covering approximately 75 percent of the net volume of NGLs expected to be sold from April 2005 through December 2006. Rising commodity prices resulted in an increase in the market value of those hedging agreements before they qualified for hedge accounting. This change in market value resulted in a $13.9 million non-cash charge to earnings for the unrealized loss on derivatives. Subsequent to the Cantera Acquisition, we evaluated the effectiveness of the derivative contracts in relation to the underlying commodities and designated the contracts as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Upon qualifying for hedge accounting, changes in the derivative contracts’ market value are accounted for as other comprehensive income or loss to the extent they are effective rather than a direct impact on net income. SFAS No. 133 requires us to continue to measure the effectiveness of the derivative contracts in relation to the underlying commodity being hedged, and we will be required to record the ineffective portion of the contracts in our net income for the respective period. Cash settlements with the counterparties to the hedging agreements will occur monthly in the future over the life of the agreements, with PVR receiving a correspondingly higher or lower amount for the physical sale of the commodity over the same period. Several derivative contracts for ethane, propane, crude oil and natural gas entered into subsequent to the Cantera Acquisition have been designated as cash flow hedges.

The fair values of our hedging instruments are determined based on third party forward price quotes for the respective commodities as of March 31, 2005. The following table sets forth our positions as of March 31, 2005:

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Based upon our assessment of our derivative contracts designated as cash flow hedges at March 31, 2005, we reported (i) a net hedging liability of approximately $16.7 million and (ii) a loss in accumulated other comprehensive income of $2.7 million. Because all hedged volumes relate to April 1, 2005, and later periods, we had no monthly settlements and recognized no net hedging losses in natural gas midstream revenues during the three months ended March 31, 2005 and 2004. Based upon future commodity prices as of March 31, 2005, $9.4 million of hedging losses are expected to be realized within the next 12 months. The amounts that we will ultimately realize will vary due to changes in the fair value of the open derivative contracts prior to settlement.

In May 2005, we entered into another contract to hedge 3,500 MMbtu per day of natural gas at $7.15 per MMbtu in the form of a fixed price swap for third quarter 2005 through fourth quarter 2006.

Interest Rate Swap

In connection with our senior unsecured notes, we entered into an interest rate swap agreement with an original notional amount of $30 million to hedge a portion of the fair value of those notes. The notional amount decreases by one-third of each principal payment. Under the terms of the interest rate swap agreement, the counterparty pays a fixed rate of 5.77 percent on the notional amount and receives a variable rate equal to the floating interest rate which will be determined semi-annually and will be based on the six month London Interbank Offering Rate plus 2.36 percent. Settlements on the swap are recorded as interest expense. In conjunction with the closing of the Cantera acquisition on March 3, 2005, we entered into an amendment in which we agreed to a 0.25 percent increase in the fixed interest rate on the notes, from 5.77 percent to 6.02 percent. At March 31, 2005, the notional amount was $29 million. This swap was designated as a fair value hedge because it has been determined that it is highly effective in mitigating the change in fair value of the hedged portion of the notes, and it has been reflected as a decrease in long-term debt of approximately $1.4 million as of March 31, 2005.

7. LONG-TERM DEBT

At March 31, 2005, and December 31, 2004, long-term debt consisted of the following (in thousands):

Concurrent with the closing of the Cantera Acquisition, Penn Virginia Operating Co., LLC, the parent of PVR Midstream LLC and a subsidiary of the Partnership, entered into a new unsecured $260 million, five-year credit agreement. The new credit agreement consists of a $150 million revolving credit facility and a $110 million term loan. The term loan and a portion of the revolving credit facility were used to fund the Cantera Acquisition and to repay borrowings under our previous credit facility. The revolving credit facility is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $10 million sublimit for the issuance of letters of credit. We have a one-time option under the revolving credit facility to increase the facility by up to $100 million upon receipt by the credit facility’s administrative agent of commitments from one or more lenders.

Proceeds of $127.7 million, including a $2.5 million contribution from our general partner, received from a subsequent public offering of 2,511,842 common units in March 2005 were used to repay the $110 million term loan and a portion of the amount outstanding under the revolving credit facility. The term loan cannot be re-borrowed.

The interest rate under the credit agreement will fluctuate based on the Partnership’s ratio of total indebtedness to EBITDA. At our option, interest shall be payable at a base rate plus an applicable margin ranging up to 1.00 percent or a rate derived from the London Interbank Offering Rate plus an applicable margin ranging from 1.00 percent to 2.00 percent.

In conjunction with the closing of the Cantera Acquisition, Penn Virginia Operating Co., LLC, also amended its senior unsecured notes to allow us to enter the natural gas midstream business and to increase certain covenant

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coverage ratios, including the debt to EBITDA test. In exchange for this amendment, we agreed to a 0.25 percent increase in the fixed interest rate on the notes, from 5.77 percent to 6.02 percent. The amendment to the notes also requires that we obtain an annual confirmation of our credit rating, with a 1.00 percent increase in the interest rate payable on the notes in the event our credit rating falls below investment grade. On March 15, 2005, our investment grade credit rating was confirmed by Dominion Bond Rating Services.

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

As of March 31, 2005, we had certain reclamation bonding requirements with respect to certain of our unleased and inactive coal properties. As of March 31, 2005, our environmental liabilities for coal properties totaled $1.5 million, which represents our best estimate of these liabilities as of that date. Given the uncertainty of when the 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, no related liabilities are accrued.

9. NET INCOME (LOSS) PER UNIT

Basic and diluted net income (loss) per unit is determined by dividing net income (loss), after deducting the general partner’s two percent interest, by the weighted average number of outstanding common units and subordinated units. At March 31, 2005, there were no dilutive units outstanding.

10. RELATED PARTY TRANSACTION

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 the Partnership. Total corporate administrative expenses charged to the Partnership totaled $0.4 million and $0.3 million for the three months ended March 31, 2005 and 2004, respectively. These costs are reflected in general and administrative expenses in the accompanying consolidated statements of income. Management believes the allocation methodologies used are reasonable.

11. DISTRIBUTIONS

We make quarterly cash distributions of our available cash, generally defined as consolidated cash receipts less consolidated cash disbursements and cash reserves established by the general partner at its sole discretion. According to the 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, 2005 (in thousands, except per unit information):

In February 2005, we paid a quarterly distribution of $0.5625 per unit, with the amount in excess of $0.55 per unit paid 85 percent to all units, pro rata, and 15 percent to the general partner. In March 2005, we announced a $0.0575 per unit increase in our quarterly distribution to $0.62 for the three months ended March 31, 2005, or $2.48 per unit on an annualized basis. The distribution will be paid on May 13, 2005, to unitholders of record on May 3, 2005. The amount in excess of $0.55 per unit will be paid 85 percent to all units, pro rata, and 15 percent to the general partner.

12. COMPREHENSIVE INCOME (LOSS)

Comprehensive income (loss) represents changes in partners’ capital during the reporting period, including net income (loss) and charges directly to partners’ capital which are excluded from net income (loss). For the three months ended March 31, 2005 and 2004, the components of comprehensive income (loss) were as follows (in thousands):

13. 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 the Chief Executive Officer and other senior officials. This group routinely reviews and makes operating and resource allocation decisions among our coal royalty, land leasing and coal services operations and natural gas midstream operations. Accordingly, our reportable segments are as follows:

Coal Royalty, Land Leasing and Coal Services

The coal royalty, land leasing and coal services segment includes:

Natural Gas Midstream

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

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In our annual report on Form 10-K for the year ended December 31, 2004, we reported two segments – coal royalty and coal services. As a result of the Cantera Acquisition, our chief operating decision maker now reviews operating results of our coal royalty, land management and coal services business on an aggregated basis in addition to the new natural gas midstream business. Accordingly, we now report these businesses as our segments. The following segment information for the three months ended March 31, 2004, has been restated to conform to the current period’s presentation. The following is a summary of certain financial information relating to the Partnership’s segments:

14. RECENT ACCOUNTING PRONOUNCEMENTS

In March 2005, the FASB released Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47), which provides guidance for applying SFAS No. 143, Accounting for Asset Retirement Obligations. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005 (December 31, 2005, for calendar-year companies). We expect no change to our results of operations or financial position as a result of implementing FIN 47.

15. SUBSEQUENT EVENT

In April 2005, we acquired approximately 13 million tons of coal reserves for $15 million (the “Alloy Acquisition”). The reserves, located on approximately 8,300 acres in the Central Appalachian region of West Virginia, will be produced from deep and surface mines with production anticipated to start in late 2005. Revenues will be earned initially from transportation-related fees on coal mined from an adjacent property, followed by royalty revenues as the mines commence production. The seller will remain on the property as the lessee and operator. The acquisition was funded with long-term debt under our revolving credit facility.

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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,” “our” or “us”) should be read in conjunction with the Consolidated Financial Statements and Notes thereto.

Overview

We are 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 royalty, land leasing and coal services (for our lessees and other third party end-users) and natural gas midstream.

Coal Royalty, Land Leasing and Coal Services Segment Overview

In our coal royalty and land leasing operations, 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. For the three months ended March 31, 2005, our lessees produced 6.7 million tons of coal from our properties and paid us coal royalty revenues of $18.1 million, for an average gross coal royalty per ton of $2.69. Approximately 83 percent of our coal royalty revenues for the first quarter of 2005 and 79 percent of our first quarter 2004 coal royalty revenues were derived from coal mined on our properties and sold by our lessees multiplied by a royalty rate per ton resulting from the higher of a percentage of the gross sales price or a fixed price per ton of coal, with pre-established minimum monthly or annual rental payments. The balance of our coal royalty revenues for the respective periods was derived from coal mined on two of our properties under leases containing fixed royalty rates per ton of coal mined and sold. The royalty rates under those leases escalate annually, with pre-established minimum monthly payments. 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. Included in our coal royalty and land leasing operations are revenues earned from the sale of standing timber on our properties. In our coal services operations, we generate revenues from providing fee-based coal preparation and transportation services to our lessees, which enhance their production levels and generate additional coal royalty revenues. We also earn revenues from third party end-users by owning and operating coal handling facilities through our joint venture with Massey Energy Company.

Our coal reserves, coal infrastructure and timber assets are located on the following six properties:

Coal is the most abundant fossil fuel energy resource in the United States, and it continues to be substantially more economical than other fossil fuel alternatives in generating electricity. Although coal represents fuel for about half of the nation’s electricity, coal combustion emits sulfur dioxide, nitrous oxides and carbon dioxide, all of which are considered pollutants. A challenge for the industry is to continue to reduce emissions while maintaining coal’s cost advantage. As environmental regulations evolve, we expect the coal industry to become increasingly environmentally friendly, and we are optimistic, therefore, that coal will continue to play a vital role in the generation of electricity. Many of our lessees have favorable transportation options to their customers, which are mostly major utilities.

We are not an operating company and do not employ any coal miners. There are several key distinctions between our coal royalty business and a coal operating business which include:

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Our lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by our lessees can be eliminated completely. None of our lessees’ violations to date, or the monetary penalties assessed, have had a material adverse effect on us or, to our knowledge, on our lessees. We do not currently expect that future compliance will have a material adverse effect on us.

While it is not possible to quantify the costs of compliance by our lessees with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closings, including the cost of treating mine water discharge when necessary. We do not accrue for such costs because our lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for our lessees’ coal. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of our lessees or their customers’ ability to use coal and may require us, our lessees or their customers to change operations significantly or incur substantial costs.

Our revenues and profitability will be adversely affected in the future if we are unable to replace or increase our reserves through acquisitions. Our management continues to focus on acquisitions of assets and energy sources necessary to meet the requirements of diverse markets and environmental regulations. Personnel were added in 2003 to evaluate acquisitions of coal reserves and coal industry-related infrastructure, and two acquisitions were completed in March and April 2005, respectively.

Natural Gas Midstream Segment Overview

On March 3, 2005, we completed the acquisition of Cantera Gas Resources, LLC (“Cantera”), a midstream gas gathering and processing company with primary locations in the mid-continent area of Oklahoma and the panhandle of Texas (the “Cantera Acquisition”). As a result of the Cantera Acquisition, we own and operate a significant set of midstream assets that includes approximately 3,400 miles of gas gathering pipelines and three natural gas processing facilities, which have 160 million cubic feet per day (MMcfd) of total capacity. Our midstream business derives revenues primarily from gas processing and gas purchase contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. We also acquired Cantera’s natural gas marketing business, which aggregates third-party volumes and sells those volumes into intrastate pipeline systems, such as Enogex and ONEOK, and at market hubs accessed by various interstate pipelines. We believe the Cantera Acquisition will establish a platform for future growth in the natural gas midstream sector and will diversify our cash flows into another long-lived asset base. The total cash paid for the Cantera Acquisition was approximately $196 million, which we funded with a $110 million term loan and with borrowings under our revolving credit facility. We used the proceeds from our sale of common units in a subsequent public offering in March 2005 to repay our term loan in full and to reduce outstanding indebtedness under our revolving credit facility.

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The following table sets forth information regarding our midstream assets:

The natural gas midstream industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets. It consists of natural gas gathering, dehydration, compression, treating, processing and transportation and natural gas liquid (“NGL”) fractionation and transportation. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

Of the services illustrated in the following diagram, we provide natural gas gathering, dehydration, compression, processing, transportation and related services to our customers.

These services are described below:

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Acquisitions and Investments

Capital expenditures, including noncash items, were as follows:

Cantera Acquisition

On March 3, 2005, we completed our acquisition of Cantera, a midstream gas gathering and processing company with primary locations in the mid-continent area of Oklahoma and the panhandle of Texas. See the description of the acquisition in the “Natural Gas Midstream Segment Overview” above. The total cash paid for the Cantera Acquisition was approximately $196 million, which we funded with a $110 million term loan and with borrowings under our revolving credit facility. The purchase price allocation for the Cantera Acquisition has not been finalized because we are still in the process of settling various post-closing adjustments with the seller, and we are waiting on final appraisals of assets acquired and liabilities assumed. We used the proceeds from our sale of common units in a

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subsequent public offering in March 2005 to repay our term loan in full and to reduce outstanding indebtedness under our revolving credit facility. See Note 4 in the Notes to Consolidated Financial Statements for pro forma financial information.

Coal River Acquisition

In March 2005, we acquired lease rights to approximately 36 million tons of undeveloped coal reserves and royalty interests in 73 producing oil and natural gas wells for $9.3 million (the “Coal River Acquisition”). The coal reserves are located adjacent to the Bull Creek tract on our Coal River property in southern West Virginia. The oil and gas wells are located in eastern Kentucky and southwestern Virginia. The acquisition was funded with long-term debt under our existing credit facility.

The coal reserves are predominantly low sulfur and high BTU content; development will occur in conjunction with our Bull Creek reserves and loadout facility that was placed into service in 2004. The oil and gas property contains approximately 2.8 billion cubic feet equivalent of net proved oil and gas reserves and current net production of approximately 166 million cubic feet equivalent on an annualized basis.

Alloy Acquisition

In April 2005, we acquired fee ownership of approximately 13 million tons of coal reserves for $15 million (the “Alloy Acquisition”). The reserves, located on approximately 8,300 acres in the Central Appalachian region of West Virginia, will be produced from deep and surface mines with production anticipated to start in late 2005. Revenues will be earned initially from transportation-related fees on coal mined from an adjacent property, followed by royalty revenues as the mines commence production. The seller will remain on the property as the lessee and operator. The acquisition was funded with long-term debt under our revolving credit facility.

Critical Accounting Policies and Estimates

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 involved in gathering information from various purchasers and measurement locations and calculating 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 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 are not expected to be significant, between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

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 internally by our geologists. Our estimates of coal reserves are updated annually and may result in adjustments to coal reserves and depletion rates that are recognized prospectively. The Partnership estimates its timber inventory using statistical information and data obtained from physical measurements, site maps, photo-types and other information gathering techniques. These estimates are updated annually and may result in adjustments of timber volumes and depletion rates, which are recognized prospectively.

Goodwill. Under Statement of Financial Accounting Standards (“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 intend to test goodwill for impairment during the fourth quarter of our fiscal year.

Intangibles. Intangible assets are primarily associated with assumed contracts and customer relationships. These intangible assets are being amortized over periods of up to 15 years, the period in which benefits are derived from the contracts and relationships assumed, and will be reviewed for impairment under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets.

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Results of Operations

Selected Financial Data – Consolidated

The decrease in net income was primarily attributable to a one-time $13.9 million non-cash charge to earnings for an unrealized loss on derivatives in our natural gas midstream segment and a $1.8 million increase in interest expense, partially offset by a $5.1 million, or 56 percent, increase in operating income. The increase in operating income was primarily attributable to the contribution of the newly acquired natural gas midstream segment and increased coal royalty revenue resulting from higher coal prices.

Coal Royalty, Land Leasing and Coal Services Segment

The coal royalty, land leasing and coal services segment includes our coal reserves, timber assets and other land assets. We enter into leases with various third-party operators for the right to mine coal reserves on the Partnership’s properties in exchange for royalty payments. We do not operate any mines. In addition to coal royalty revenues, we generate coal services revenues from fees charged to lessees for the use of coal preparation and transloading facilities. We also generate revenues from 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 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.

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Operations and Financial Summary – Coal Royalty, Land Leasing and Coal Services Segment

Revenues. Coal royalty revenues increased due to higher royalties per ton despite a decrease in production. Average royalties per ton increased to $2.69 in the first quarter of 2005 from $2.12 in the comparable 2004 period. The increase in the average royalties per ton was primarily due to stronger market conditions for coal and the resulting higher coal prices. Production decreased by 16 percent primarily as a result of the factors discussed below.

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Coal services revenues increased primarily as a result of equity earnings from the coal handling joint venture we acquired in July 2004 and start-up operations at our West Coal River and Bull Creek facilities in July 2003 and February 2004, respectively.

Operating Costs and Expenses. The decrease in aggregate operating costs and expenses primarily relates to decreases in operating expenses and depreciation, depletion and amortization (“DD&A”), which were partially offset by an increase in general and administrative expenses.

Operating expenses decreased due to a decrease in royalty expense resulting from decreased production on the subleased portion of the Coal River property as previously described in the “Revenues” paragraphs above.

The increase in general and administrative expenses was primarily attributable to increased payroll costs allocated to the Partnership by the general partner.

DD&A expense decreased primarily as a result of lower production.

Interest Expense. Interest expense increased primarily due to interest incurred on additional borrowings on our revolving credit facility and a new term loan in March 2005 to finance the Cantera Acquisition.

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.

The natural gas midstream segment derives revenues primarily from gas processing and gas purchase contracts with natural gas producers and from fees charged for gathering natural gas volumes and providing other related services. Revenues, profitability and future rate of growth of the natural gas midstream segment are highly dependent on market demand and prevailing 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.

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Operations and Financial Summary – Natural Gas Midstream Segment