Item 2.  Management's Discussion and Analysis of Financial Conditions and Results of Operations

      The following analysis of financial condition and results of operations of Penn Virginia Corporation and subsidiaries should be read in conjunction with the Consolidated Financial Statements and Notes thereto.

 Overview

        Penn Virginia Corporation ("Penn Virginia" or the "Company") is an independent energy company that is engaged in two primary business segments.  Our oil and gas segment explores for, develops, produces and sells crude oil, condensate and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States.  Our coal royalty and land management segment operates through our ownership in Penn Virginia Resource Partners, L.P. (the "Partnership" or "PVR").  Penn Virginia and PVR are both publicly traded on the New York Stock Exchange under the symbols PVA and PVR, respectively.  Due to our control of the general partner of PVR, the financial results of the Partnership are included in our consolidated financial statements.  However, PVR functions with a capital structure that is independent of the Company, consisting of its own debt instruments and publicly traded common units.  The following diagram depicts our ownership of PVR:

Diagram

      As a result of our ownership in the Partnership, we receive cash payment from PVR in the form of quarterly cash distributions.  We received approximately $4.2 million of cash distributions during the three months ended March 31, 2004 and $4.1 million in the first three months of 2003.  As part of our ownership of PVR's general partner, we also own the rights, referred to as incentive distribution rights, to receive an increasing percentage of quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved.  As of March 31, 2004, PVR had not achieved a level of distributions to allow us to receive an increased percentage of available cash.

      We are committed to increasing value to our shareholders by conducting a balanced program of investment in our two business segments.  In the oil and gas segment, we expect to execute a program combining relatively low risk, moderate return development drilling in the Appalachian region of Virginia and West Virginia with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions.  In addition to our continuing conventional development program, we are expanding our eastern presence by developing coalbed methane ("CBM") gas reserves in Appalachia.  By employing horizontal drilling techniques, we expect to increase the value from the CBM reserves we own. 

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      In the coal royalty and land management segment, PVR continually evaluates acquisition opportunities that are accretive to cash available for distribution to PVR unit holders, of which we are the largest single unitholder. These opportunities include, but are not limited to, acquiring additional coal properties and reserves, acquiring or constructing assets for coal services which would provide a fee-based revenue stream, and acquiring mid-stream hydrocarbon-related transportation assets or other operating units that would strategically fit within the Partnership.

      Our oil and gas capital expenditures for 2004 are now expected to be between $110 and $115 million compared to $100 million in our original 2004 capital expenditures budget.  Borrowings against our credit facility were $55 million out of $150 million available as of March 31, 2004, and we expect to fund our 2004 capital expenditures with a combination of internal cash flow and credit facility borrowings.

      Coal-related capital expenditures on existing properties in 2004 are expected to be less than $1.0 million.  As of March 31, 2004, PVR had borrowed $92.5 million against its debt facilities.  Cash flow from operations, is expected to be adequate for PVR to fund 2004 capital expenditures.

      Three Months Ended March 31, 2004 Performance - Oil and Gas Segment
     During the first quarter of 2004, we increased oil and gas production to 6.5 Bcfe, an 11 percent increase over 5.8 Bcfe produced in the first quarter of 2003.  This increase resulted from the Company's active drilling program in Mississippi, increased production from horizontally-drilled coalbed methane formations in Appalachia and production from mid-2003 discoveries and field extensions in the Stella, south Creole and Broussard fields in south Louisiana.  These increases were offset in part by natural field declines.  Average daily oil and gas production increased to 70.9 MMcfe in the first quarter of 2004 compared to 64.7 MMcfe in the first quarter of 2003. 

      Three Months Ended March 31, 2004 Performance - Coal Royalty and Land Management Segment (PVR)
    During the first quarter of 2004, coal royalty revenues were $16.9 million compared with $11.5 million for the first quarter of 2003, an increase of $5.4 million, or 47 percent.  The increase in revenues related to higher production and increased average royalties per ton received from PVR lessees.  Production by PVR lessees increased by 1.5 million tons, or 24 percent, to 8.0 million tons in the first quarter of 2004 from 6.4 million tons in the first quarter of 2003.  A significant part of this increase was attributed to increased production from a longwall mining operation located on PVR's Coal River property. 

Critical Accounting Policies and Estimates
      The process of preparing financial statements in accordance with GAAP requires the management of the Company 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.

      Reserves.  The estimates of oil and gas reserves are the single most critical estimate included in our financial statements. There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities including projecting the total quantities in place, future production rates and the timing of future development expenditures.  In addition, reserve estimates of new discoveries are less precise than those of producing properties due to the lack of a production history.  Accordingly, these estimates are subject to change as additional information becomes available. 

      Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions at the end of the respective years.  Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods. Proved undeveloped reserves are those quantities that require additional capital investment through drilling or well recompletion techniques.

      Reserve estimates become the basis for determining depletive write-off rates, recoverability of historical cost investments and the fair value of properties subject to potential impairments.

      There are several factors which could change our estimates of oil and gas reserves. Significantly higher or lower product prices could lead to changes in the amount of reserves due to economic limits.  An additional factor that could result in a change of recorded reserves is the reservoir decline rates being different than those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and the inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards ("SFAS") No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates.

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      Depreciation and depletion of oil and gas producing properties is determined by the unit-of-production method and could change with revisions to estimated proved recoverable reserves.

       Oil and Gas Revenues . Oil and gas sales revenues are recognized when crude oil and natural gas volumes are produced and sold for our account.  As a result of the numerous requirements necessary to gather information from purchasers or various measurement locations, calculate volumes produced, perform field and wellhead allocations and distribute and disburse funds to various working interest partners and royalty owners, the collection of revenues from oil and gas production may take up to 60 days following the month of production. Therefore, accruals for revenues and accounts receivable are made based on estimates of our share of production, particularly from properties that are operated by our partners. Since the settlement process may take 30 to 60 days following the month of actual production, our financial results will include estimates of production and revenues for the related time period. Any differences between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

      Coal Royalties . Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership's lessees and the corresponding revenues from those sales. Since PVR is not the mine operator, it does not have the actual production and revenues amounts until approximately 30 days following the month of production. Therefore, the financial results of the Partnership will include estimated revenues and accounts receivable for this 30 day period. Any differences between the actual amounts ultimately received and the original estimates are recorded in the period they become finalized.

       Oil and gas properties .  We use the successful efforts method to account for our oil and gas properties.  Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized.  Annual lease rentals, exploration costs, geological, geophysical and seismic costs and exploratory dry-hole costs are expensed as incurred. 

      A portion of the carrying value of the Company's oil and gas properties is attributable to unproved properties. At March 31, 2004, the costs attributable to unproved properties were approximately $60 million. These costs are not currently being depreciated or depleted. As exploration work progresses and the reserves on these properties are proven, capitalized costs of the properties will be written off through depletion expense. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any write downs of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

      Asset retirement obligations .  In accordance with SFAS No. 143, Accounting for Asset Retirement Obligations, we make estimates of the timing and future costs of plugging and abandoning wells.  Estimated abandonment dates will be revised in the future based on changes to related economic lives, which vary with product prices and production costs.  Estimated plugging costs may also be adjusted to reflect changing industry experience.  Increases in operating costs and decreases in product prices would increase the estimated amount of our plugging and abandonment obligations and increase depletion expense.  Our cash flows would not be affected until costs to plug and abandon were actually incurred.

        Included in net income for the three months ended March 31, 2003 was $1.4 million, or $0.15 per diluted share, related to the adoption of SFAS No. 143.

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Oil and Gas Segment

        In our oil and gas segment, we explore for, develop and produce crude oil and natural gas in the eastern and Gulf Coast onshore regions of the United States. Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond the Company's control.  Crude oil prices are generally determined by global supply and demand.  Natural gas prices are influenced by national and regional supply and demand.  A substantial or extended decline in the prices of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of our oil and natural gas properties. Our future profitability and growth is also highly dependent on the results of our exploratory and development drilling programs.

*Includes the effect of hedging activities in the respective periods.

        Revenues. Oil and gas total revenues increased $3.0 million to $37.5 million in first quarter of 2004 from $34.5 million in the first quarter of 2003.

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        Crude oil and natural gas production increased to 6.5 Bcfe in the first quarter of 2004, an 11 percent increase over 5.8 Bcfe in the first quarter of 2003.  Increased oil and natural gas production accounted for the majority of the $3.0 million increase in total oil and gas revenues from the first quarter of 2003 to the first quarter of 2004.  The production increase was primarily due to the Company's active drilling program in Mississippi, increased production from horizontally-drilled coalbed methane formations in Appalachia and production from mid-2003 discoveries and field extensions in the Stella, south Creole and Broussard fields in south Louisiana, offset in part by natural field declines.

        Approximately 89 percent of our first quarter 2004 production was natural gas, for which the average realized natural gas price received was $5.90 per Mcf compared with $6.09 per Mcf in the first quarter of 2003, a three percent decrease.  The average realized oil price received was $30.07 per barrel for the first quarter of 2004, up four percent from $28.95 per barrel in the first quarter of 2003.

      For the three months ended March 31, 2004, approximately 37 percent of our natural gas and 34 percent of our crude oil production was hedged at an average floor price of $3.71 per MMbtu and ceiling price of $5.59 per MMbtu for natural gas, and an average price of $28.83 per barrel for crude oil. Gains and losses from hedging activities are included in revenues when the hedged production occurs.  We recognized a loss on settled hedging activities of $1.2 million in the first quarter of 2004 and a loss of $4.1 million in the first quarter of 2003.

    See Note 4 (Hedging Activities) in the Notes to the Consolidated Financial Statements for details of costless collars and fixed price swaps. 

      Operating expenses.   The Oil and Gas segment's aggregate operating costs and expenses for the first quarter of 2004 were $22.4 million, compared with $19.3 million for the same period in 2003, an increase of $3.1 million, or 16 percent. The increase in operating costs and expenses primarily related to increases in exploration expenses and depreciation, depletion and amortization.

      Exploration expenses for the three months ended March 31, 2004 and 2003 consisted of the following (in thousands):

      Exploration expenses increased from $4.2 million in the first quarter of 2003 to $5.6 million in the first quarter of 2004 primarily due to unproved leasehold impairment expense recorded in the first quarter of 2004 related to expiring options and the write off of unproved properties due to unsuccessful exploration drilling. 

      Oil and gas depreciation, depletion and amortization ("DD&A") increased from $8.1 million in the first quarter of 2003 to $9.3 million in the first quarter of 2004 primarily due to higher production as discussed earlier, and an increase in the weighted average DD&A rate from $1.39 per Mcfe in the first quarter of 2003 to $1.44 per Mcfe in the first quarter of 2004.  The increase in the weighted average DD&A rate was the result of the additional capital investment made during the past year.

Coal Royalty and Land Management Segment (PVR)

       The coal royalty and land management segment includes PVR's coal reserves, timber assets and other land assets.  The assets, liabilities and earnings of PVR are fully consolidated in our financial statements, with the public unitholders' interest reflected as a minority interest.

      The Partnership enters into leases with various third-party operators for the right to mine coal reserves on the Partnership's properties in exchange for royalty payments.  Approximately 79 percent of the Partnership's first quarter of 2004 coal royalty revenues and 66 percent of its first quarter of 2003 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments.  The balance of the Partnership's 2004 and 2003 coal royalty revenues were based on fixed royalty rates which escalate annually, also with pre-established monthly minimums.  In addition to coal royalty revenues, the Partnership generates coal service revenues from fees charged to lessees for the use of coal preparation and transportation facilities.  The Partnership also generates revenues from the sale of timber on its properties.

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      The coal royalty stream is impacted by several factors, which PVR 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 the Partnership's lessees or their customers' ability to use coal and may require PVR, its lessees or its lessee's customers to change operations significantly or incur substantial costs.

      Revenues. PVR's revenues in the first quarter of 2004 were $18.0 million compared with $13.2 million for the same period in 2003, an increase of $4.8 million, or 36 percent.  The increase in revenues primarily related to increased coal royalties received from PVR lessees.

      Coal royalties revenues for the three months ended March 31, 2004 were $16.9 million compared with $11.5 million for the same period in 2003, an increase of $5.4 million, or 47 percent.  Average royalties per ton increased to $2.12 in the first quarter of 2004 from $1.78 in the comparable 2003 period.  The increase in the average royalty per ton was primarily due to stronger market conditions resulting in higher prices for coal sold by PVR's lessees.  Production by PVR lessees increased by 1.6 million tons, or 24 percent, to 8.0 million tons in the first quarter of 2004 from 6.4 million tons in the first quarter of 2003.

      Operating Costs and Expenses. PVR's aggregate operating costs and expenses for the first quarter of 2004 were $8.8 million, compared with $7.2 million for the same period in 2003, an increase of $1.6 million, or 22 percent. The increase in operating costs and expenses primarily related to increases in operating expenses and depreciation, depletion and amortization.

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      Operating expenses were $1.7 million and $0.8 million for the three months ended March 31, 2004 and 2003, respectively.  This increase was a result of an increase in production by lessees on subleased properties, primarily on PVR's Coal River property.  Production on subleased properties increased to 1.5 million tons in the first quarter of 2004 from 0.3 million tons in the first quarter of 2003.

      Depreciation, depletion and amortization for the three months ended March 31, 2004 was $4.8 million compared with $4.2 million for the same period of 2003, an increase of $0.6 million or 13 percent.  This increase was a result of increased production over the comparable periods.

        Interest Expense. Interest expense was $1.3 million for the three months ended March 31, 2004, compared with $0.8 million for the same period in 2003, an increase of $0.5 million, or 69 percent. The increase was primarily due to PVR's closing of a private placement of $90 million senior unsecured notes payable in March 2003, which bears interest at a fixed rate 5.77 percent and matures in 2013.  Prior to the private placement, the $90.0 million was included on PVR's revolving credit facility, which charged interest at the Eurodollar rate plus an applicable margin which ranges from 1.25 percent to 2.25 percent or an effective 3.45 percent interest rate for the first quarter of last year.

    Minority Interest . Minority interest was $4.5 million for the three months ended  March 31, 2004 compared with $3.0 million for the same period in 2003, an increase of $1.5 million, or 49 percent. The increase was primarily due to the increase in the Partnership's net income for the comparable periods.

Corporate and Other Segment

          The Corporate and Other segment primarily consists of oversight and administrative functions.

      G&A expenses decreased from $2.3 million in the first quarter of 2003 to $1.9 million in the same period of 2004.  The $0.4 million decrease was primarily attributable to the absence in 2004 of consulting and advisory services related to the consideration of various shareholder proposals incurred in 2003, offset in part by a general increase in staffing levels.

      Interest costs associated with unproved leaseholds were capitalized during the first quarter of 2004 and 2003 as activities were in progress to bring projects to their intended use.  Accordingly, we capitalized all corporate direct credit facility interest costs, amounting to $0.4 million and $0.5 million in the first quarters of 2004 and 2003, respectively.  Interest costs which were expensed in the Corporate and Other segment related to the amortization of debt issuance costs.

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Capital Resources and Liquidity
 

      The Company and PVR have separate credit facilities, and neither entity guarantees the debt of the other.  Since PVR's public offering, with the exception of cash distributions received by the Company from PVR, the cash needs of each entity have been met independently with a combination of operating cash flows, credit facility borrowings and, in the case of PVR's December 2002 acquisition of coal reserves from affiliates of Peabody Energy Corporation ("Peabody"), issuance of new partnership units.  We expect that our cash needs and the cash needs of PVR will continue to be met independently of each other with a combination of these funding sources.  Below are summarized cash flow statements for 2004 and 2003 consolidating the oil and gas (and corporate) and the coal royalty and land management (PVR) segments.

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      Except where noted, the following discussion of cash flows and contractual obligations relates to consolidated results of the Company.

Cash flows from Operating Activities
      Consolidated net cash provided from operating activities was $24.5 million in the first quarter of 2004, compared with $18.8 million for the same period in 2003.  The oil and gas and corporate segment's net cash provided by operations was $14.3 million in the first quarter of 2004 and $10.4 million for the same period in 2003.  The increase was primarily due to higher production of natural gas.  Cash in excess of working capital needs for both periods was used to help fund capital expenditures during the respective period.  Cash provided by operations of the coal royalty and land management segment was $10.3 million in first quarter of 2004, compared with $8.4 million in the first quarter of 2003.  The increase was due to both increased production and average royalty rates realized.

Cash flows from Investing Activities
      Consolidated net cash used in investing activities was $15.0 million in the first quarter of 2004, compared with $49.3 million in the first quarter of 2003.  During the first quarters of both years, we used cash primarily for capital expenditures for oil and gas development and exploration activities and acquisitions of oil and gas properties, including a $33.5 million acquisition of oil and gas properties in south Texas in the first quarter of 2003.

      Capital expenditures totaled $20.6 million in the first quarter of 2004, compared with $52.7 million in the first quarter of 2003.  The following table sets forth capital expenditures by segment, made during the periods indicated.

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*      In February 2004, PVR released 51,000 units which have been held in escrow since December 2002.  In exchange for the units, PVR received additional reserves on the Northern Appalachia properties.

        We are committed to expanding our oil and natural gas operations over the next several years through a combination of exploration, development and acquisition of new properties.  We have a portfolio of assets which balances relatively low risk, moderate return development projects in Appalachia and Mississippi with relatively moderate risk, potentially higher return development projects and exploration prospects in south Texas and south Louisiana. 

        Oil and gas segment capital expenditures for 2004 are now expected to be between $110 million and $115 million compared to $100 million in our original capital expenditures budget.  The increase in anticipated 2004 capital expenditures is primarily due to increased development drilling in our Mississippi Selma Chalk, east Texas Cotton Valley and south Texas areas and by increased pipeline construction costs to support our increasing horizontal coalbed methane production in Appalachia.  These increases are expected to be offset in part by a $2 million to $3 million reduction in exploration drilling expenditures. We continually review drilling and other capital expenditure plans and may continue to change these amounts based on industry conditions and the availability of capital.  We believe our cash flow from operations and sources of debt financing are sufficient to fund our 2004 planned capital expenditures program as revised.

Cash flows from Financing Activities
      Consolidated net cash used in financing activities was $14.5 million in the first quarter of 2004 compared with $26.7 million of cash provided from financing activities in the first quarter of 2003.  During the first quarter of 2004, $9 million of borrowings under PVA's credit facility were repaid. Credit facility borrowings provided approximately $33.6 million of cash in the first quarter of 2003 used primarily to fund a south Texas acquisition. For the three months ended March 31, 2004 and 2003, we received $4.2 million and $4.1 million of cash distributions, respectively, for our ownership of PVR units.  Funds from both of these sources were primarily used for capital expenditure needs. 

      As of March 31, 2004, we had outstanding borrowings of $55 million against our $300 million revolving credit facility that has an initial commitment of $150 million and which can be expanded at our option to our current approved borrowing base of $200 million.  We also had $0.3 million outstanding in letters of credit as of March 31, 2004.  The financial covenants require us to maintain levels of debt-to-earnings and dividend limitation restrictions.  We are currently in compliance with all of our covenants.

      We have a $5 million line of credit, which had no borrowings against it as of March 31, 2004.  The line of credit is effective through June 2004 and is renewable annually. 

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      As of March 31, 2004, PVR had outstanding borrowings of $92.5 million, consisting of $2.5 million borrowed against a $100 million revolving credit facility and $90.0 million attributable to PVR's senior unsecured notes.

      In conjunction with the senior unsecured notes, PVR entered into an interest rate swap agreement with a notional amount of $30 million, to hedge a portion of the senior unsecured notes. This swap is designated as a fair value hedge and has been reflected as a decrease in long-term debt of $13 thousand as of March 31, 2004.  Under the terms of the interest rate swap agreement, the counterparty pays the Partnership a fixed annual rate of 5.77 percent on a total notional amount of $30 million, and the Partnership pays the counterparty 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. 

      Future Capital Needs and Commitments .  For the remainder of 2004, we anticipate making total capital expenditures, excluding acquisitions, of approximately $90 million to $95 million.  Nearly all of these expenditures are expected to be made in our oil and gas segment, and are expected to be funded primarily by operating cash flow.  Additional funding will be provided as needed from our credit facility, under which we had $95 million of borrowing capacity as of March 31, 2004. 

      On November 3, 2003 we entered into an agreement with a provider of seismic data, whereby we have received a license to access 5,000 square miles of 3-D seismic data over the next two years.  We paid $5 million in the first quarter of 2004 and have a remaining commitment of $4 million to be paid in the first quarter of 2005.

      In our coal royalty and land management segment, PVR anticipates making total capital expenditures, excluding acquisitions, of approximately $0.1 million for coal services related projects.  Part of PVR's strategy is to make acquisitions which increase cash available for distribution to its unitholders. PVR's ability to make these acquisitions in the future will depend in part on the availability of debt financing and on its ability to periodically use equity financing through the issuance of new units. Since completing the December 2002 acquisition of coal reserves from affiliates of Peabody, PVR's ability to incur additional debt has been restricted due to limitations in its debt instruments.  As of March 31, 2004, PVR had approximately $26 million of borrowing capacity available under the PVR credit facility.  This limitation may have the effect of necessitating the issuance of new units by PVR, as opposed to using debt, to fund acquisitions in the future.

Environmental Matters

        Our businesses are subject to various environmental hazards.  Several federal, state and local laws, regulations and rules govern the environmental aspects of our businesses. Noncompliance with these laws, regulations and rules can result in substantial penalties or other liabilities. We do not believe our environmental risks are materially different from those of comparable companies nor that cost of compliance will have a material adverse effect on our profitability, capital expenditures, cash flows or competitive position. However, there is no assurance that future changes in or additions to laws, regulations or rules regarding the protection of the environment will not have such an impact.  We believe we are materially in compliance with environmental laws, regulations and rules.

        In conjunction with the Partnership's leasing of property to coal operators, environmental and reclamation liabilities are generally the responsibilities of the Partnership's lessees.  Lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary.

Recent Accounting Pronouncements

      A reporting issue has arisen regarding the application of certain provisions of SFAS No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets to companies in the extractive industries, including oil and gas and coal industry companies.  The issue is whether SFAS No. 142 requires registrants to classify the costs of mineral rights as intangible assets in the balance sheet, apart from other capitalized oil and gas property and coal property costs, and provide specific footnote disclosures.  The Emerging Issues Task Force has added the treatment of oil and gas mineral rights to an upcoming agenda, which may result in a change in how we are currently classifying these assets.  In April 2004, the Financial Accounting Standards Board ("FASB") issued a FASB Staff Position, which amends certain sections of SFAS No. 141 and No. 142 relating to the characterization of coal mineral rights.  Beginning in the second quarter of 2004, the Partnership will reclassify its leased coal mineral rights back to tangible property.

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      Oil and Gas Mineral Rights.  Historically, we have included the costs of mineral rights associated with extracting oil and gas as a component of oil and gas properties under SFAS No. 19. Financial Accounting and Reporting by Oil and Gas Producing Companies.   If it is ultimately determined that SFAS No. 142 requires oil and gas companies to classify costs of mineral rights associated with extracting oil and gas as a separate intangible assets line item on the balance sheet, we would be required to reclassify approximately $156 million and $157 million as of March 31, 2004 and December 31, 2003, respectively, out of oil and gas properties and into a separate line item for oil and gas mineral interest.  Our cash flows and results of operations would not be affected since such intangible assets would continue to be depleted and assessed for impairment in accordance with successful efforts accounting rules.  Further, we do not believe the classification of the costs of mineral rights associated with extracting oil and gas as intangible assets would have any impact on our compliance with covenants under our debt agreements.

      Coal Mineral Rights.  Based on the application of certain provisions of SFAS No. 141 and SFAS No. 142, the Partnership has classified costs associated with the leasing of coal reserves acquired after June 30, 2001 as an intangible asset in other assets on the balance sheet, apart from other capitalized property costs.  The amount capitalized related to a mineral right represents its fair value at the time such right was acquired less accumulated amortization.  The transition provisions of SFAS No. 141 and SFAS No. 142 only require the reclassification of amounts acquired after the June 30, 2001 effective date, unless previously maintained records make it possible to reclassify rights acquired prior to that date.  Prior to June 30, 2001, the Partnership did not separately allocate acquisition costs between owned mineral interests (tangible property) and leased mineral rights (intangible property), as such interests were part of the same coal seams.  Accordingly, the Partnership only classified coal mineral rights acquired after June 30, 2001 as an intangible asset in the accompanying consolidated balance sheet.