Pro Forma
	Asset Retirement
Adoption Date		Obligation
	(in thousands)
January 1, 2000	$1,558
December 31, 2000	$1,743
December 31, 2001	$2,019
March 31, 2002	$2,347
December 31, 2002	$2,685

5.  HEDGING ACTIVITIES

Commodity Hedges

    From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility.  The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps.  All derivative financial instruments are recognized in the financial statements at fair value in accordance with SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138.

    All derivative instruments are recorded on the balance sheet at fair value.  If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings.  To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.  Currently, we are utilizing only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management policy, which has been reviewed and approved by the Board of Directors.

    We formally document all relationships between hedging instruments and hedged items, as well as the risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assess, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. We measure hedge effectiveness on a period basis. When it is determined that a derivative is not highly effective as a hedge, or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.

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  When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in earnings prospectively.

    Gains and losses on hedging instruments when settled are included in natural gas or crude oil production revenues in the period that the related production is delivered.

    The fair values of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing prices as of March 31, 2003.  The following table sets forth our positions as of March 31, 2003:

	Notional	Fixed Price or
Time Period	Quantities	Effective Floor/Ceiling Price	Fair Value
Natural Gas	(MMbtu per Day)	(Per Mmbtu)	(in thousands)
Costless collars
April 1, 2003 -September 30, 2003	5,000	$3.37 / $5.05	$             (344)
April 1, 2003 - October 31, 2003	5,000	$2.92 / $4.42	(851)
April 1, 2003 - December 31, 2003	5,000	$5.00 / $7.10	418
October 1, 2003 - April 30, 2004	7,272	$3.50 / $5.00	(999)
April 1, 2003 - June 30, 2004	7,500	$3.50 / $5.28	(1,248)
April 1, 2003 - July 31, 2004	4,000	$3.72 / $6.97	(26)
Swaps
April , 2003 - January 31, 2005	1,100 to 5,300	$4.70	(248)
Crude Oil	(Bbls per Day)	(Per Bbl)
Costless collars
April 1, 2003 - June 30, 2003	500	$23.00 / $28.75	(151)
Swaps
July 1, 2003 - June 30, 2004	120	$26.58	26
April 1, 2003 - January 1, 2005	50 to 250	$26.93	23
Total			$          (3,400)

    Based upon our assessment of our derivative contracts at March 31, 2003, we reported (i) an approximate price risk management liability of $3.9 million, an approximate price risk management asset of $0.5 million and (ii) a loss in accumulated other comprehensive income of $2.2 million, net of a related income tax benefit of $1.2 million.  In connection with monthly settlements, we recognized net hedging losses in natural gas and oil revenues of $4.1 million for the three months ended March 31, 2003.  Based upon future oil and natural gas prices as of March 31, 2003, $2.9 million of hedging losses are expected to be realized within the next 12 months.  The amounts ultimately realized will vary due to changes in the fair value of the open derivative contracts prior to settlement.  We recognized net hedging gains of $1.2 million for the three months ended March 31, 2002.

Interest Rate Swap

      In March 2003, PVR entered into an interest rate swap agreement with a notional amount of $30 million, to hedge a portion of the fair value of its 5.77 percent senior unsecured notes which mature over a ten year period. This swap is designated as a fair value hedge and has been reflected as a decrease of long-term debt of approximately $0.1 million as of March 31, 2003, with a corresponding increase in long-term assets. Under the terms of the interest rate swap agreement, the counterparty pays PVR a fixed annual rate of 5.77 percent on a total notional amount of $30 million, and PVR 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.  See Note 5 (Long-term Debt) for a description of the underlying debt instrument to which the interest rate swap applies.

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6.  LONG-TERM DEBT

    At March 31, 2003 and December 31, 2002, long-term debt consisted of the following (in thousands):

	March 31,		December 31,
	2003		2002
	(Unaudited)
Penn Virginia revolving credit facility	$          48,000		$         16,000
PVR senior unsecured notes, net of fair value hedge of $79 thousand	89,921		-
PVR revolving credit facility	2,500		47,500
PVR term loan	-		43,387
	$        140,421		$       106,887

Penn Virginia Revolving Credit Facility

      We have a $150 million secured revolving credit facility which expires in October 2004 (the "Revolver") with a group of major commercial banks.  Subsequent to March 31, 2003, the borrowing base was increased from $140 million to $150 million.

      The Revolver is governed by a borrowing base calculation and will be redetermined semi-annually.  We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.375 to 1.875 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the federal funds rate plus a margin ranging from 0.375 to 0.875 percent or the prime rate as announced by the agent bank. The weighted average interest rate on borrowings incurred during the year ended December 31, 2002 was approximately 3.0 percent.  The Revolver provides for the issuance of letters of credit that are limited to no more than an aggregate of $10 million.  The financial covenants require us to maintain certain levels of net worth, debt-to-earnings, and earnings-to-interest. Certain dividend limitation restrictions are also included.  We are currently in compliance with all of our covenants.

PVR Revolving Credit Facilty

      In connection with the closing of PVR's initial public offering in October 2001, PVR entered into a three-year $50 million revolving credit facility (the "PVR Revolver") with a syndicate of major commercial banks, which expires in October 2004. The PVR Revolver is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $5.0 million distribution sublimit that is available for working capital needs and distributions and a $5.0 million sublimit for the issuance of letters of credit.

      Indebtedness under the PVR Revolver will bear interest, at PVR's option, at either (i) the higher of the federal funds rate plus 0.50 percent or the prime rate as announced by PNC Bank, National Association or (ii) the Euro-dollar rate plus an applicable margin which ranges from 1.25 percent to 1.75 percent based on PVR's ratio of consolidated indebtedness to consolidated EBITDA (as defined in the credit agreement) for the four most recently completed fiscal quarters. The PVR Revolver prohibits PVR from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. The financial covenants of the PVR Revolver require PVR to maintain certain levels of debt-to-earnings and earnings-to-interest.  The Partnership is currently in compliance with all of the PVR Revolver covenants.

PVR Senior Unsecured Notes

      In March 2003, PVR closed a private placement of $90 million of senior unsecured notes payable (the "PVR Notes").  The PVR Notes bear interest at a fixed rate of 5.77 percent and mature over a ten year period ending in March 2013, with semi-annual interest payments through March 2004 followed by principal and interest payments beginning in September 2004.  Proceeds of the PVR Notes after the payment of expenses related to the offering were used to repay a $43.4 million PVR term loan and to repay the majority outstanding under its Revolver.

      The $43.4 million PVR term loan that was repaid in March 2003 originated in conjunction with the closing of PVR's initial public offering in October 2001.  PVR borrowed $43.4 million under the term loan and purchased and pledged $43.4 million of U.S. Treasury notes, which secured the credit facility. In 2002, the U.S. Treasury Notes were liquidated for the purpose of funding acquisitions.

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      Concurrent with the closing of the PVR Notes, PVR also entered into an interest rate derivative transaction to convert $30 million of the debt from a fixed interest rate to a floating interest rate, as described further in Note 5 (Hedging Activities, Interest Rate Swap).

      The PVR Notes prohibit PVR from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the Notes, occurs or would result from the distribution. In addition, the PVR Notes contain various covenants similar as to those contained in the PVR Revolver.

7.  COMMITMENTS AND CONTINGENCIES

Legal

    We are involved in various legal proceedings arising in the ordinary course of business. While the ultimate results of these proceedings cannot be predicted with certainty, we believe these claims will not have a material effect on our financial position, liquidity or operations.

Advisory Services

    On March 25, 2002, we entered into an agreement with an investment banking firm to provide financial advisory services in connection with our receipt and consideration of various shareholder proposals.  The fees payable under this agreement cannot be calculated with certainty until the time of actual payment which will occur on or before November 30, 2003.  As of March 31, 2003, based on a range of probable payment amounts, we have recognized a cumulative liability of approximately $2.3 million for services rendered in connection with this agreement, of which $0.8 million was recognized for the three months ended March 31, 2003.  We will continue to accrue additional expenses under this agreement in accordance with our best estimate of the amount due for such services.

8.  EARNINGS PER SHARE

    The following is a reconciliation of the numerators and denominators used in the calculation of basic and diluted earnings per share ("EPS") for income from continuing operations for the three months ended March 31, 2003 and 2002 (in thousands, except per share data).

	Three Months
	Ended March, 2003
	2003		2002
Income before cumulative effect of change in accounting principle	$                9,123		$                3,370
Cumulative effect of change in accounting principle	1,363		-
Net income	$              10,486		$                3,370
Weighted average shares, basic	8,952		8,909
Effect of dilutive securities:
Stock options	44		98
Weighted average shares, diluted	8,996		9007
Income before cumulative effect of change in accounting principle, basic	$                  1.02		$                  0.38
Cumulative effect of change in accounting principle, basic	0.15		-
Net income per share, basic	$                  1.17		$                  0.38
Income before cumulative effect of change in accounting principle, diluted	$                  1.01		$                  0.37
Cumulative effect of change in accounting principle, diluted	0.15		-
Net income per share, diluted	$                  1.16		$                  0.37

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9. COMPREHENSIVE INCOME

    Comprehensive income represents all changes in equity during the reporting period, including net income and charges directly to equity, which are excluded from net income. For the three month periods ended March 31, 2003 and 2002, the components of comprehensive income were as follows (in thousands):

						Three Months
						Ended March 31,
						2003		2002
Net income						$                 10,486		$                   3,370
Unrealized holding losses on derivative financial instruments, net of tax						(3,538)		(2,921)
Reclassification adjustment for derivative financial instruments, net of tax						2,670		(822)
Comprehensive income (loss)						$                   9,618		$                    (373)

10.  SEGMENT INFORMATION

    Penn Virginia's operations are classified into two operating segments:

    Oil and Gas - crude oil and natural gas exploration, development and production.

    Coal Royalty and Land Management - the leasing of mineral rights and subsequent collection of royalties and the development and harvesting of timber.  This segment's activities are conducted through Penn Virginia's ownership interest in Penn Virginia Resource Partners, L.P.

      All other - primarily represents corporate functions.

				Coal Royalty
				and Land	All
			Oil and Gas	Management	Other	Consolidated
			(in thousands)
For the three months ended March 31, 2003:
Revenues			$            34,548	$            13,241	$                  227	$            48,016
Operating costs and expenses			11,249	2,947	2,659	16,855
Depreciation, depletion and amortization			8,103	4,218	27	12,348
Operating income (loss)			15,196	6,076	(2,459)	18,813
Interest expense						(936)
Interest income						439
Income before minority interest
and taxes						$            18,316
Additions to property and equipment			$            48,151	$              1,269	$                   77	$            49,497
For the three months ended March 31, 2002:
Revenues			$            13,378	$            10,755	$                 250	$            24,383
Operating costs and expenses			5,039	2,593	1,371	9,003
Depreciation, depletion and amortization			5,655	895	52	6,602
Operating income (loss)			2,684	7,267	(1,173)	8,778
Interest expense						(470)
Interest income						553
Income before minority interest
and taxes						$              8,861
Additions to property and equipment			$             8,129	$                 514	$                 329	$              8,972

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11.  NEW ACCOUNTING STANDARDS

        In November 2002, the FASB issued Interpretation No. 45 ( FIN 45), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5, Accounting for Contingencies, relating to a guarantor's accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and the Company cannot reasonably estimate the impact of adopting FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements.

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

      We operate in two business segments: oil and gas and coal royalty and land management. The oil and gas segment includes the exploration for, and the development and production of, crude oil, condensate and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States, and our ownership of mineral rights to oil and gas reserves. The coal royalty and land management segment includes the leasing of coal reserves, services provided by fee-based assets, and the sale of timber, owned by Penn Virginia Resource Partners, L.P. (the "Partnership" or "PVR"). The assets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders' 55 percent interest in PVR reflected as a minority interest.  Selected operating and financial data by segment is presented below.

Critical Accounting Policies and Estimates

      Oil and Gas Properties.  We use the successful efforts method of accounting for our oil and gas operations. Under this method of accounting, costs to acquire mineral interests in oil and gas properties and to drill and equip development wells (including development dry holes) are capitalized and amortized on a unit-of-production basis over the remaining life of proved developed reserves and proved reserves, respectively.  Costs of drilling exploratory wells are initially capitalized, and later charged to expense upon determination that the well does not justify commercial development.  Other exploratory costs, including annual delay rentals and geological and geophysical costs, are charged to expense when incurred.

      The costs of unproved leaseholds are capitalized pending the results of exploration efforts. Unproved leasehold costs are assessed periodically, on a property-by-property basis, and a loss is recognized to the extent, if any, that the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds and amortized on a unit-of-production basis.

      Other Property and Equipment.  Other property and equipment is carried at cost and includes expenditures for additions and improvements, which substantially increase the productive lives of existing assets.  Maintenance and repair costs are expensed as incurred. Depreciation of property and equipment is generally computed using the straight-line method over their estimated useful lives, varying from 3 years to 20 years.  Coal properties are depleted on an area-by-area basis at a rate based upon the cost of the mineral properties and estimated proven and probable tonnage therein.  When an asset is retired or sold, its cost and related accumulated depreciation are removed from the accounts. The difference between undepreciated cost and proceeds from disposition is recorded as a gain or loss.

      Impairment of Long-Lived Assets.  We review our long-lived assets to be held and used, including proved oil and gas properties and the Partnership's coal properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.  An impairment loss must be recognized when the carrying amount of an asset exceeds the sum of the undiscounted estimated future cash flows.  In this circumstance, we would recognize an impairment loss equal to the difference between the carrying value and the fair value of the asset.  Fair value is estimated to be the expected present value of future net cash flows from proved reserves, discounted utilizing a risk-free interest rate commensurate with the remaining lives for the respective oil and gas properties.

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      Oil and Gas Revenues. Oil and gas revenues are recognized when crude oil and natural gas volumes are produced and sold for our account.  Each working interest owner in a well generally has the right to a specific percentage of production, and often actual production sold for any particular owner will differ from such owner's ownership percentage.  When, under contract terms, these differences are settled in cash, revenues are adjusted accordingly.

      Coal Royalties. Coal royalty revenues are recognized on the basis of tons of coal sold by the Partnership's lessees and the corresponding revenue from those sales. Coal leases other than those with Peabody Energy Corporation ("Peabody") affiliates are based on minimum monthly or annual payments, a minimum dollar royalty per ton and/or a percentage of the gross sales price.  Peabody leases are based on fixed royalties which escalate annually and also provide for minimum monthly payments.

      Coal Services. Coal services revenues are recognized when lessees use the Partnership's facilities for the processing and transportation of coal. Coal services revenues consist of fees collected from the Partnership's lessees for the use of the Partnership's loadout facility, coal preparation plants and dock loading facility.

      Timber. Timber revenues are recognized as timber is sold on a contract basis where independent contractors harvest and sell the timber and, from time to time, in a competitive bid process involving sales of standing timber on individual parcels.  Title and risk of loss pass to the independent contractors upon the execution of the contract. In addition, if the contractors do not harvest the timber within the specified time period, the title of the timber reverts back to the Partnership with no refund of original payment.

      Minimum Rentals.  Most of the Partnership's lessees are required to make minimum monthly or annual payments that are generally recoupable over certain time periods.  These minimum payments are recorded as deferred income.  If the lessee recoups a minimum payment through production, the deferred income attributable to the minimum payment is recognized as coal royalty revenues.  If a lessee fails to meet its minimum production for the recoupment period, the deferred income attributable to the minimum payment is recognized as minimum rental revenues.  Revenues associated with minimum rentals are included in other revenues.

      Price Risk Management Activities.  From time to time, we enter into derivative financial instruments to mitigate our exposure to natural gas and crude oil price volatility.  The derivative financial instruments, which are placed with major financial institutions that we believe are minimum credit risks, take the form of costless collars and swaps.  All derivative instruments are recorded on the balance sheet at fair value.  If the derivative does not qualify as a hedge or is not designated as a hedge, the gain or loss on the derivative is recognized currently in earnings.  To qualify for hedge accounting, the derivative must qualify either as a fair value hedge, cash flow hedge or foreign currency hedge.  Currently, we are utilizing only cash flow hedges and the remaining discussion will relate exclusively to this type of derivative instrument. All hedge transactions are subject to our risk management policy, which has been reviewed and approved by the Board of Directors.  We formally document all relationships between hedging instruments and hedged items, as well as its risk-management objective and strategy for undertaking various hedge transactions. This process includes linking all derivatives that are designated as cash flow hedges to forecasted transactions. We also formally assess, both at inception of the hedge and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in cash flows of hedged transactions. We measure hedge effectiveness on a period basis. When it is determined that a derivative is not highly effective as a hedge, or that it has ceased to be a highly effective hedge, we discontinue hedge accounting prospectively.  When hedge accounting is discontinued because it is probable that a forecasted transaction will not occur, the derivative will continue to be carried on the balance sheet at its fair value, and gains and losses that were accumulated in other comprehensive income will be recognized in earnings immediately. In all other situations in which hedge accounting is discontinued, the derivative will be carried at its fair value on the balance sheet, with changes in its fair value recognized in earnings prospectively.  Gains and losses on hedging instruments when settled are included in natural gas or crude oil production revenues in the period that the related production is delivered.  The fair values of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing prices.

      Reserves.  There are many uncertainties inherent in estimating crude oil and natural gas reserve quantities, projecting future production rates and the timing of future development expenditures.  In addition, reserve estimates of new discoveries are more imprecise than those of properties with 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.  Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods.

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Results of Operations - Three Months Ended March 31, 2003 Compared to Three Months Ended March 31, 2002

    We reported net income of $10.5 million, or $1.16 per share (diluted), for the three months ended March 31, 2003, compared with $3.4 million, or $0.37 per share (diluted), for the three months ended March 31, 2002.  Revenues increased $23.6 million, primarily as a result of increased natural gas and crude oil prices received and production increases for natural gas, crude oil and coal.  Operating expenses were $13.6 million higher during the three months ended March 31, 2003 than the 2002 comparable period primarily due to expense increases related to our acquisition of certain south Texas oil and gas properties in January 2003, and PVR's acquisition of certain coal reserves from Peabody in December 2002 (the "Peabody Acquisition"). See "Acquisitions" for more information.

Variances in revenues and operating expenses are explained in more detail in the segment discussions following.

General and administrative.  On a consolidated basis, general and administrative expense was $5.9 million for the three months ended March 31, 2003, compared with $4.5 million for the same period in 2002.  The $1.4 million increase was due primarily to advisory services and legal fees related to the consideration of various shareholder proposals, a general increase in the number of employees for the Company and an increase in insurance premiums.

Interest expense.  On a consolidated basis, interest expense was $0.9 million for the three months ended March 31, 2003, compared with $0.5 million for the same period in 2002, an increase of $0.4 million or 80 percent.  The increase was primarily due to long-term borrowings in connection with the Peabody Acquisition and other acquisitions in 2002.

Interest income.  Interest income was $0.3 million for the three months ended March 31, 2003, compared with $0.6 million for the same period in 2002.  The decrease was primarily due to the existence of U.S. Treasury Notes in the first quarter of 2002, which were liquidated during the last half of last year.

Minority Interest.  Minority interest for the three months ended March 31, 2003 was $3.0 million, compared to $3.6 million for the same period in 2002.  The decrease was primarily due to a decrease in PVR's net income for the respective periods, offset in part by an increase in ownership percentage by the public unitholders to approximately 55 percent for the first quarter of 2003 from 48 percent for the same period in 2002.

Income taxes.  The effective tax rate for the three month period ended March 31, 2003 was 40 percent, compared to 36 percent for the comparable period in 2002.  The effective tax rate has increased primarily as the result of the absence of Section 29 tax credits, for which the tax regulations expired at the end of 2002.  At this time, there is no new legislation which allows similar tax benefits.

Acquisitions

Oil and Gas

      On January 22, 2003, we acquired a 25 percent non-operated working interest in properties located in a producing field in south Texas ("the south Texas acquisition").  Proved reserves of 31.8 billion cubic feet equivalent of natural gas were acquired in a cash transaction with a private investor group for $32.5 million, or $1.02 per thousand cubic feet equivalent.  The acquisition, which was effective January 1, 2003, was financed with the Company's existing credit facility.  Nine producing wells were acquired at the time of the acquisition, and comprised approximately one-third of the total proved reserves acquired.  Four wells have been drilled in the field since the acquisition date and are currently producing.  Additional wells are expected to be drilled over the next two to three years to fully develop the field.

Coal Royalty and Land Management

      In December 2002, PVR announced the formation of a strategic alliance with Peabody, the largest private sector coal company in the world. Central to the transaction was the purchase and leaseback of approximately 120 million tons of predominately low sulfur, low BTU coal reserves located in New Mexico (80 million tons) and predominately high sulfur, high BTU coal reserves in northern West Virginia (40 million tons). The Peabody Acquisition, which included 8,800 mineral acres, was funded with $72.5 million in cash and the issuance by the Partnership to Peabody of 1,522,325 common units and 1,240,833 class B common units, a newly created series of units. Of the 1,240,833 class B common units issued, 293,700 are currently being held in escrow pending (i) Peabody obtaining approvals from the State of New Mexico regarding certain of the New Mexico reserves we purchased and (ii) Peabody acquiring and transferring to us certain of the West Virginia reserves we purchased. As a result of the escrowed class B common units, approximately five million tons of coal reserves were excluded from reserve totals, and 293,700 class B common units were excluded from units issued, in the Partnership's financial statements for the period ended March 31, 2003.

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      In addition to the Peabody Acquisition, in August 2002, PVR purchased approximately 16 million tons of reserves located on the Upshur properties in northern Appalachia for $12.3 million (the "Upshur Acquisition"). The Upshur Acquisition was PVR's first exposure outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominately high sulfur, high BTU coal reserves.

      In May 2001, PVR acquired the Fork Creek property in West Virginia, purchasing approximately 53 million tons of coal reserves for $33 million. In early 2002, the operator at Fork Creek filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. Fork Creek's operations were idled on March 4, 2002. The operator continued to pay minimum royalties until PVR recovered its lease on August 31, 2002. In November 2002, PVR purchased various infrastructure at Fork Creek, including a 900-ton per hour coal preparation plant, a unit-train loading facility and a railroad-granted rebate on coal loaded through the facility for $5.1 million plus the assumption of approximately $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. With control of the Fork Creek reserves, permits and the critical infrastructure, PVR is working diligently to put a new, financially stable operator in place at Fork Creek. As is customary in its operations, PVR intends to assign all related reclamation liabilities to a new operator.

      During the first quarter of 2003, the Peabody and Upshur Acquisitions were the primary reasons for increased coal royalty revenue and increased depreciation, depletion and amortization expense for PVR, while the Fork Creek property was idle and incurred mine maintenance-related operating expenses during the quarter.

Oil and Gas Segment

    Operating income for the oil and gas segment was $15.2 million for the three months ended March 31, 2003, compared with $2.7 million for the comparable period of 2002.  Operational and financial data for the Company's oil and gas segment for the three months ended March 31, 2003 and 2002 is summarized as follows:

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Operations and Financial Summary

				Three Months
				Ended March 31,
Production				2003				2002
Natural gas (MMcf)				4,928				4,265
Oil and condensate (MBbls)				149				92
Total Equivalent production (Mmcfe)				5,822				4,817
				(in thousands, except per unit amount)
Revenues:
Natural gas * (including $/Mcf)				$            30,000		$               6.09		$            11,337		$                2.66
Oil and condensate * (including $/Bbl)				4,313		28.95		1,994		21.67
Other income				235		-		47		-
Total revenues (including $/Mcfe)				34,548		5.93		13,378		2.78
Expenses (including $/Mcfe):
Lease operating expenses				2,605		0.45		1,789		0.37
Exploration expenses				4,245		0.73		44		0.01
Taxes other than income				2,604		0.45		1,252		0.26
General and administrative				1,795		0.31		1,954		0.41
Depreciation and depletion				8,103		1.39		5,655		1.17
Total expenses				19,352		3.33		10,694		2.22
Operating Income (including $/Mcfe)				$            15,196		$                2.60		$              2,684		$                0.56

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

    For the three months ended March 31, 2003, approximately 32 percent of our natural gas and 39 percent of our crude oil production was hedged at an average floor price of $3.23 per MMbtu and ceiling price of $4.79 per MMbtu for natural gas, and an average floor price of $23.91 per barrel and ceiling price of $28.33 per barrel for crude oil.  The effects of these hedges were to decrease the average natural gas prices received by $0.77 per Mcf and the average crude oil prices received by $2.21 per barrel.

    See Note 5 (Hedging Activities) in the Notes to the Consolidated Financial Statements for details of costless collars and fixed price swaps.  We will continue when circumstances warrant to hedge the price received for market-sensitive production through the use of fixed price term contracts or derivatives.

Natural Gas.  Natural gas sales increased by $18.7 million, or 165 percent, for the three months ended March 31, 2003, compared with the same period of 2002.  The average natural gas price received was 129 percent higher in the first quarter of 2003, compared with the same quarter of the prior year.  In addition to the price increase, production increased 663 MMcf, or 16 percent, in the first quarter of 2003 compared with the same period in 2002.  The production increase primarily related to the south Texas acquisition and the drilling program in 2002 and the first quarter of this year.

Oil and Condensate.  Oil sales increased by $2.3 million for three months ended March 31, 2003, compared with the same period of 2002.  The increase was primarily due to increased production related to the south Texas acquisition in January 2003.  Average realized prices received for crude oil production also increased by $7.28 per barrel, or 34 percent.

    Lease Operating Expenses.  Operating expenses for the three months ended March 31, 2003, were $2.6 million, compared with $1.8 million in the comparable period of 2002.  The $0.8 million increase was primarily attributable to operating expenses related to wells drilled and acquired subsequent to the first quarter of 2002.

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Exploration Expenses.  Exploration expenses for the three months ended March 31, 2003, increased to $4.2 million, compared with $44 thousand in the comparable period of 2002.  The increase was primarily due to the acquisition of seismic data to evaluate both existing and new prospects.  Additionally, approximately $0.4 million related to an unsuccessful well was expensed in the first quarter of 2003.

Taxes other than on Income.  Taxes other than on income increased to $2.6 million for three months ended March 31, 2003 from $1.3 million in the first quarter of 2002.  The increase was primarily due to higher prices received for natural gas and crude oil, as well as increased production in the first quarter of 2003 versus the same period in 2002.

Depreciation and Depletion.  Depreciation and depletion for the three months ended March 31, 2003 increased to $8.1 million, compared with $5.7 million in the comparable period of 2002.  The increase was primarily due to higher production related to the 2002 drilling program and the south Texas acquisition in January of 2003, as well as higher depletion rates caused by higher cost bases relative to reserves added.

Coal Royalty and Land Management Segment

      The following table sets forth PVR's revenues, operating expenses and operating statistics for the three months ended March 31, 2003 compared with the same period in 2002.

	Three Months
	Ended March 31,
Financial Highlights:	2003		2002	Percentage
	(in thousands, except prices)			Change
Revenues:
Coal royalties	$                   11,451		$                     8,491	35%
Coal services	493		411	20%
Timber	556		582	(4%)
Minimum rentals	605		870	(30%)
Other	136		401	(66%)
Total revenues	13,241		10,755	23%
Operating costs and expenses:
Operating	840		885	(5%)
Taxes other than income	296		161	84%
General and administrative	1,811		1,547	17%
Depreciation and depletion	4,218		895	371%
Total operating costs and expenses	7,165		3,488	105%
Operating income	$                    6,076		$                     7,267	(16%)

Coal Royalties.  Coal royalty revenue for the three months ended March 31, 2003 was $11.5 million compared to $8.5 million for the same period in 2002, an increase of $3.0 million, or 35 percent.  Over these respective periods, the production by PVR lessees increased 2.6 million tons, or 69 percent, primarily due to the Peabody and Upshur Acquisitions in 2002. The increase in production was partially offset by a decrease in the average royalty per ton of $0.45, or 20 percent, over the same periods, which was primarily attributable to the lower fixed royalty rates per ton received from Peabody leases.

Coal Services.  Coal services revenue increased $0.1 million, or 20 percent, to $0.5 million in the first quarter of 2003, compared with $0.4 million in the same period of 2002. The increase was attributable to small preparation plants PVR made available to two of its leases and a slight increase in throughput fees from tonnage going through PVR's loadout facility.

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Timber Sales.  Timber revenue remained constant at $0.6 million for the three months ended March 31, 2003 and March 31, 2002.  Volume sold declined 297 thousand board feet (Mbf), or 10 percent, to 2,829 Mbf in the first quarter of 2003, compared with 3,126 Mbf for the same period in 2002. The decrease in volume sold was due to the timing of parcel sales.  This decrease was mitigated by an increase in the average price received, which totaled $187 per Mbf in the first quarter of 2003 compared with $174 per Mbf in the comparable period of 2002.  The increase in the average price received primarily resulted from stronger market conditions.

Minimum Rentals.  Minimum rentals revenue decreased to $0.6 million for the three months ended March 31, 2003 from $0.9 million in the comparable period of 2002.  The decrease was primarily due to the timing of expiring recoupments from two of PVR's lessees in the first quarter of 2002.

Other Income.  Other income decreased to $0.1 million for the three months ended March 31, 2003, compared with $0.4 million for the same period in 2002.  The $0.3 million decrease was primarily due to the expiration of a railroad rebate received for the use of a specific portion of railroad by one of PVR's lessees, which was paid in full in the fourth quarter of 2002.

Operating Expenses.  Operating expenses decreased by 5 percent, to $0.8 million in the first quarter of 2003, compared with $0.9 million in the same period of 2002.  The decrease was due to a decrease in production on PVR's subleased properties, offset in part by costs to maintain an idle mine on PVR's Fork Creek property.

 Taxes other than Income.  Taxes other than income increased $0.1 million, or 84 percent, to $0.3 million for the three months ended March 31, 2003, compared with $0.2 million in the same period of 2002. The variance was attributable to increased property taxes as a result of assuming the property tax obligation on the Fork Creek property upon reacquiring the lease from the bankrupt lessee and an increase in West Virginia franchise taxes relating to the Peabody Acquisition.

General and Administrative. General and administrative expenses increased $0.3 million, or 17 percent, to $1.8 million in the first quarter of 2003, from $1.5 million in the same period of 2002. The increase was primarily attributable to additional expenses associated with the Peabody Acquisition and an increase in insurance premiums.

Depreciation and Depletion.  Depreciation and depletion for the three months ended March 31, 2003 was $4.2 million compared with $0.9 million for the same period of 2002, an increase of 371 percent.  This increase was a result of higher depletion rates caused by higher cost bases relative to reserves added as well as increased production, both of which relate primarily to the Peabody and Upshur Acquisitions completed during the last half of 2002.

Liquidity and Capital Resources

      The Company and PVR operate with independent capital structures, and the Company receives cash from PVR in the form of quarterly cash distributions for the subordinated and common limited partner units it owns, currently comprising approximately 42.5 percent of PVR's ownership, and for its general partnership interest in PVR, currently two percent.  The Company and PVR have separate credit facilities, for which neither entity guarantees the debt of the other.  Since PVR's public offering in October 2001, 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 Peabody Acquisition, issuance of new partnership units.  We expect that the cash needs of the Company and PVR will continue to be met separately with a combination of these funding sources.

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

Cash Flows from Operating Activities

    Net cash provided by operating activities was $18.8 million in the first quarter of 2003, compared with $11.4 million in the first quarter of 2002.  The increase was mostly due to higher realized natural gas and crude oil prices, offset in part by higher exploration and operating expenses.

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Cash Flows from Investing Activities

    During the first quarter of 2003, we used $49.3 million in investing activities, compared with $8.7 million in the first quarter of 2002.  Cash was used during these periods primarily for capital expenditures for oil and gas development and exploration activities and acquisition of oil and gas properties.  Capital expenditures totaled $52.7 million in the first quarter of 2003, compared with $9.0 million in the same period in 2002.  The following table sets forth capital expenditures made during the periods indicated.

	Three Months
	Ended March 31,
	2003		2002
	(in thousands)
Oil and gas
Development drilling	$          10,361		$              6,455
Exploratory drilling	801		630
Lease acquisitions	36,000		798
Field projects	494		235
Seismic and other	3,690		-
Oil and gas capital expenditures	51,346		8,118
Coal royalty and land management (PVR)
Lease acquisitions	1,254		98
Support equipment and facilities	15		416
Coal royalty and land management capital expenditures	1,269		514
Other	77		329
Total capital expenditures	$          52,692		$            8,961

      We drilled a total of 26 gross (21.3 net) wells in the first quarter of 2003, compared to 33 gross (27.5 net) wells in the same period in 2002.

      In our Gulf Coast region, we drilled six successful wells, including five development wells and one exploration well.  Four development wells were drilled in the Vicksburg objective in the south Texas field we acquired in January 2003 and five to ten more wells are expected to be drilled in that field during the remainder of 2003.  Our initial drilling projects in South Louisiana during the first quarter of 2003 resulted in two successes in as many attempts.  Construction and installation of the production facilities and sales pipeline are underway.  A 3-D seismic survey is currently underway in the area, and could identify additional development potential.  A successful wildcat well was also completed in another South Louisiana field and another exploratory well is currently drilling in the same field, with one or two additional exploration wells planned for the remainder of 2003. 

      In our Eastern region, we drilled 20 wells, including 19 successful development wells and one unsuccessful exploration well.  Twelve successful Selma Chalk development wells were drilled in Mississippi. We plan to drill 50 to 60 more gross wells in Mississippi during the remainder of 2003.  Seven conventional multi-pay development wells were also drilled in West Virginia during the first quarter, and we plan to drill 40 to 50 more gross conventional wells in West Virginia and Virginia during the rest of 2003. Drilling operations also commenced on two horizontal coalbed methane patterns in West Virginia, with completion expected during the second quarter.  Six to eight additional horizontal coalbed methane patterns are expected to be drilled during the remainder of 2003. 

      On April 1, 2003, we completed the acquisition from a private company of approximately 4,000 acres prospective in the Selma Chalk in the Baxterville Field in Mississippi.  Over 90 potential drilling locations have been identified on the acquired acreage, with drilling to commence in 2003.  

      Oil and gas segment capital expenditures for the remainder of 2003 are estimated to be $65 to $84 million.  Approximately $50 to $60 million of the planned oil and gas capital expenditures are expected to be for development drilling projects, including horizontal coalbed methane drilling in Appalachia and development of the south Texas properties we acquired in January 2003. Exploration drilling is expected to be approximately $9 to $12 million of the planned expenditures, concentrated primarily in south Louisiana and south Texas.  Expenditures to build our library of 3-D seismic data for drilling prospect generation is expected to be approximately $3 to $4 million, and lease acquisition and field project expenditures are expected to be $4 to $8 million.  Capital expenditures for the remainder of 2003 in the coal royalty and land management segment are expected to be up to $3 million for the construction of fee-based infrastructure facilities. We continually review drilling and other capital expenditure plans and may 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 2003 planned capital expenditure program.

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Cash Flows from Financing Activities

    Net cash provided by financing activities totaled $26.7 million in the first quarter of 2003, compared to $1.1 million for the same period in 2002.  Credit facility borrowings provided approximately $33.6 million of cash from financing activities during the first quarter of 2003, offset in part by $2.0 million of dividend payments and distributions to PVR's minority unitholders of $3.9 million.

    Penn Virginia has a $150 million secured revolving credit facility (the "Revolver") with a final maturity of October 2004, and we had borrowed $48.0 million against it as of March 31, 2003.  As part of our semi-annual borrowing base re-determination completed in April 2003, the Revolver's borrowing base was increased from $140 million to $150 million.  Under the Revolver, we have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.375 to 1.875 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the federal funds rate plus a margin ranging from 0.375 to 0.875 percent or the prime rate as announced by the agent bank.  The financial covenants of the Revolver include, but are not limited to, maintaining: (i) a ratio of not more than 3.0:1.0 of total debt to EBITDAX (as defined by the Revolver's credit agreement), (ii) a ratio of not less than 2.5:1.0 of EBITDAX to interest expense and (iii) a minimum amount of tangible net worth (as defined by the Revolver's credit agreement).  We are currently in compliance with all of the covenants in the Revolver.  We also currently have a $5.0 million line of credit, which had no borrowings against it as of March 31, 2003.  The line of credit annually renews.

      PVR has a credit facility with a final maturity in October 2004 consisting of a $50.0 million unsecured revolving credit facility (the "PVR Revolver").  As of March 31, 2003, PVR had borrowed $2.5 million against the PVR Revolver. The PVR Revolver is available for general partnership purposes, including working capital, capital expenditures and acquisitions, and includes a $5.0 million distribution sublimit that is available for working capital needs and distributions and a $5.0 million sublimit for the issuance of letters of credit. Under the PVR Revolver, PVR has the option to elect interest at either (i) the higher of the federal funds rate plus 0.50 percent or the prime rate as announced by the agent bank or (ii) the Euro-dollar rate plus an applicable margin which ranges from 1.25 percent to 1.75 percent based on PVR's ratio of consolidated indebtedness to consolidated EBITDA (as defined in the credit agreement) for the four most recently completed fiscal quarters. PVR is required to reduce all working capital borrowings under the working capital sublimit of the Revolver to zero for a period of at least 15 consecutive days once each calendar year. The PVR Revolver prohibits PVR from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the credit agreement, occurs or would result from the distribution. The financial covenants of the PVR Revolver include, but are not limited to, maintaining: (i) a ratio of not more than 2.5:1.0 of total debt to consolidated EBITDA (as defined by the credit agreement) and (ii) a ratio of not less than 4.00:1.00 of consolidated EBITDA to interest.  The Partnership is currently in compliance with all of the Revolver covenants.  Based primarily on the total debt to consolidated EBITDA covenant and subsequent to PVR's  issuance of senior unsecured notes as described below, available borrowing capacity under the PVR Revolver as of March 31, 2003 was approximately $17 million.

      In March 2003, a $43.4 million unsecured term loan (the "PVR Term Loan), which was part of PVR's credit facility was repaid and retired, and is not available for future borrowings by PVR. Part of the proceeds from the issuance of senior unsecured notes by PVR, as described below, was used to repay the PVR Term Loan.

      Also in March 2003, PVR closed a private placement of $90 million of senior unsecured notes payable (the "PVR Notes"). The PVR Notes bear interest at a fixed rate of 5.77 percent and mature over a ten year period ending in March 2013, with semi-annual interest payments through March 2004 followed by principal and interest payments beginning in September 2004.  Proceeds of the PVR Notes after the payment of expenses related to the offering were used to repay the $43.4 million PVR Term Loan and to repay the majority outstanding on the PVR Revolver. The PVR Notes prohibit PVR from making distributions to unitholders and distributions in excess of available cash if any potential default or event of default, as defined in the PVR Notes, occurs or would result from the distribution.  In addition, the PVR Notes contain various covenants that are the same as the PVR Revolver, with the exception of the financial coverage covenants, which for the PVR Notes require PVR to maintain ratios of (i) not more than 3.0:1.0 of total debt to consolidated EBITDA (as defined in the PVR Notes) and (ii) not less than 3.5:1.0 of consolidated EBITDA to interest. PVR believes it is currently in compliance with all of the covenants of the PVR Notes.

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      Concurrent with the closing of the PVR Notes, PVR also entered into an interest rate derivative transaction to convert $30 million of notional debt from a fixed interest rate to a floating interest rate, as described further in the "Interest Rate Risk" section of "Quantitative and Qualitative Disclosures about Market Risk" following.

    Management believes its sources of funding are sufficient to meet short and long-term liquidity needs not funded by cash flows from operations. Our primary sources of funding for the remainder of 2003 are expected to be cash flows from operations supplemented as needed by borrowings under our Revolver.  Excluding acquisitions, PVR's primary funding sources are also expected to be cash flows from operations supplemented as needed by borrowings under the PVR Revolver.

Legal and Environmental

      Mountaintop Removal Litigation.  On January 29, 2003, the United States Fourth Circuit Court of Appeals (the "Circuit Court") vacated an injunction issued in May 2002 by the United States District Court for the Southern District of West Virginia (the "District Court"). This injunction had prohibited the Huntington, West Virginia office of the U.S. Army Corps of Engineers (the "Corps") from issuing permits under Section 404 of the Clean Water Act for the construction of valley fills for the disposal of coal mining overburden. These valleys typically contain streams that, under the Clean Water Act, are considered navigable waters of the United States.  The District Court had found that the Corp's permitting of overburden valley fills under Section 404 was a violation of the Clean Water Act since Section 404 allows only the permitting of fill material deposited for a beneficial purpose and not for mere waste disposal such as the disposal of coal overburden. The Circuit Court reversed this finding, concluding, instead, that overburden valley fills may be permitted under Section 404 and remanded the case back to the District Court for further proceedings not inconsistent with the Circuit Court's opinion.

Recent Accounting Pronouncements

    In June 2001, the Financial Accounting Standards Board ("FASB") issued 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. The Standard applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset. SFAS No. 143 requires that the fair value of a liability for an asset retirement obligation be 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 this additional carrying amount is depreciated over the life of the asset.  The liability is accreted at the end of each period through charges to operating expense. If the obligation is settled for other than the carrying amount of the liability, we will recognize a gain or loss on settlement. We adopted the provisions of SFAS No. 143 effective January 1, 2003.  In conjunction with the initial adoption, we recorded a cumulative effect of change in accounting principle, net of taxes, of approximately $1.4 million as an increase to income. In addition, we recorded an asset retirement obligation of approximately $2.7 million.

        In November 2002, the FASB issued Interpretation No. 45 ( FIN 45), Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of the Indebtedness of Others, which clarifies the requirements of SFAS No. 5, Accounting for Contingencies, relating to a guarantor's accounting for and disclosures of certain guarantees issued. FIN 45 requires enhanced disclosures for certain guarantees. It also will require certain guarantees that are issued or modified after December 31, 2002, including certain third-party guarantees, to be initially recorded on the balance sheet at fair value. For guarantees issued on or before December 31, 2002, liabilities are recorded when and if payments become probable and estimable. The financial statement recognition provisions are effective prospectively, and the Company cannot reasonably estimate the impact of adopting FIN 45 until guarantees are issued or modified in future periods, at which time their results will be initially reported in the financial statements.

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Item 3.  Quantitative and Qualitative Disclosures about Market Risk

      Price Risk Management.  Our price risk management program permits the utilization of derivative financial instruments (such as futures, forwards, option contracts and swaps) to mitigate the price risks associated with fluctuations in natural gas and crude oil prices as they relate to our anticipated production. These contracts and/or financial instruments are designated as cash flow hedges and accounted for in accordance with SFAS No. 133, as amended by SFAS No. 137 and SFAS No. 138.  See Note 5 (Hedging Activities) of the Notes to the Consolidated Financial Statements, for more information. The derivative financial instruments are placed with major financial institutions that we believe are of minimum credit risk.  The fair value of our price risk management assets are significantly affected by energy price fluctuations. As of March 31, 2003, our open commodity price risk management positions on average daily volumes were as follows:

Natural gas hedging positions	Costless Collars						Swaps
	MMBtu		Price / MMBtu (a)				MMBtu		Price
	Per Day		Floor		Ceiling		Per Day		/MMBtu
Second Quarter 2003	26,500		$         3.70		$         5.69		3,399		$         4.70
Third Quarter 2003	26,500		$         3.70		$         5.69		2,570		$         4.70
Fourth Quarter 2003	24,500		$         3.80		$         5.80		2,034		$         4.70
First Quarter 2004	19,500		$         3.54		$         5.51		1,800		$         4.70
Second Quarter 2004	14,137		$         3.56		$         5.70		1,533		$         4.70
Third Quarter 2004	11,000		$         3.97		$         5.45		1,367		$         4.70
Fourth Quarter 2004	3,707		$         4.00		$         5.24		1,234		$         4.70
First Quarter 2005 (January)	-		$               -		$               -		1,100		$         4.70
(a) The costless collar natural gas prices per MMBtu per quarter include the effects of basis differentials, If any, that may be hedged.
Crude oil hedging positions	Costless Collars						Swaps
	Barrels		Price / Barrel				Barrels		Price
	Per Day		Floor		Ceiling		Per Day		/Barrel
Second Quarter 2003	500		$       23.00		$       28.75		170		$       26.93
Third Quarter 2003	-		$              -		$              -		250		$       26.76
Fourth Quarter 2003	-		$              -		$              -		220		$       26.74
First Quarter 2004	-		$              -		$              -		207		$       26.73
Second Quarter 2004	-		$              -		$              -		193		$       26.71
Third Quarter 2004	-		$              -		$              -		63		$       26.93
Fourth Quarter 2004	-		$              -		$              -		57		$       26.93
First Quarter 2005 (January)	-		$              -		$              -		50		$       26.93

      Interest Rate Risk.  The carrying value of our debt approximates fair value.  At March 31, 2003, we had $48.0 million of long-term debt borrowed against our secured revolving credit facility (the "PVA Revolver").  The PVA Revolver matures in October 2004 and is governed by a borrowing base calculation that is re-determined semi-annually.  We have the option to elect interest at (i) LIBOR plus a Eurodollar margin ranging from 1.375 to 1.875 percent, based on the percentage of the borrowing base outstanding or (ii) the greater of the prime rate or federal funds rate plus a margin ranging from 0.375 to 0.875 percent.  As a result, our 2003 interest costs will fluctuate based on short-term interest rates relating to the PVA Revolver.   

      Additionally, PVR refinanced $90.0 million of credit facility borrowings with ten year, senior unsecured notes payable which have a 5.77 percent fixed interest rate throughout their term. However, PVR executed an interest rate swap transaction for $30.0 million of the amount refinanced to hedge the fair value of its senior unsecured notes.  The interest rate swap is accounted for as a fair value hedge. PVR executed the transaction in a method that achieved hedge accounting in compliance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 137 and SFAS No. 138. The debt PVR incurs in the future under their credit facility will bear variable interest at either the applicable base rate or a rate based on LIBOR.

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Forward-Looking Statements

    Statements included in this report which are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions related thereto) are forward-looking.  In addition, we and our representatives may from time to time make other oral or written statements that are also forward-looking statements.

        Such forward-looking statements may include, among other things, statements regarding development activities, capital expenditures, acquisitions and dispositions, drilling and exploration programs, expected commencement dates and projected quantities of oil, gas, or coal production, as well as projected demand or supply for coal, crude oil and natural gas, all of which may affect sales levels, prices and royalties realized by Penn Virginia and PVR.

        These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting Penn Virginia and PVR and, therefore, involve a number of risks and uncertainties.  Penn Virginia cautions that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

        Important factors that could cause the actual results of operations or financial condition of Penn Virginia to differ materially from those expressed or implied in the forward-looking statements include, but are not necessarily limited to:  the cost of finding and successfully developing oil and gas reserves; the cost to PVR of finding new coal reserves; the ability of Penn Virginia to acquire new oil and gas reserves and of PVR to acquire new coal reserves on satisfactory terms; the price for which such reserves can be sold; the volatility of commodity prices for oil and gas and coal; the risks associated with having or not having price risk management programs; PVR's ability to lease new and existing coal reserves; the ability of PVR's lessees to produce sufficient quantities of coal on an economic basis from PVR's reserves; the ability of lessees to obtain favorable contracts for coal produced from PVR's reserves; Penn Virginia's ability to obtain adequate pipeline transportation capacity for its oil and gas production; competition among producers in the oil and gas and coal industries generally; the extent to which the amount and quality of actual production differs from estimated recoverable proved oil and gas reserves and coal reserves; unanticipated geological problems; availability of required drilling rigs, materials and equipment; the occurrence of unusual weather or operating conditions including force majeure events; the failure of equipment or processes to operate in accordance with specifications or expectations; delays in anticipated start-up date of Penn Virginia's oil and natural gas production and PVR's lessees' mining operations; environmental risks affecting the drilling and producing of oil and gas wells or the mining of coal reserves; the timing of receipt of necessary governmental permits by Penn Virginia and by PVR's lessees; labor relations and costs; accidents; changes in governmental regulation or enforcement practices, especially with respect to environmental, health and safety matters, including with respect to emissions levels applicable to coal-burning power generators; uncertainties relating to the outcome of mountaintop removal litigation and issues regarding coal truck weight restriction enforcement and legislation; risks and uncertainties relating to general domestic and international economic (including inflation and interest rates) and political conditions; and the experience and financial condition of lessees of PVR's coal reserves including their ability to satisfy their royalty, environmental, reclamation and other obligations to PVR and others. Many of such factors are beyond Penn Virginia's ability to control or predict.  Readers are cautioned not to put undue reliance on forward-looking statements.

      While Penn Virginia periodically reassesses material trends and uncertainties affecting Penn Virginia's results of operations and financial condition in connection with the preparation of Management's Discussion and Analysis of Results of Operations and Financial Condition and certain other sections contained in Penn Virginia's quarterly, annual or other reports filed with the Securities and Exchange Commission, Penn Virginia does not undertake any obligation to review or update any particular forward-looking statement, whether as a  result of new information, future events or otherwise.

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Item 4.  Controls and Procedures

(a)  Evaluation of Disclosure Controls and Procedures:

     Within the 90 day period prior to the filing date of this Quarterly Report on Form 10-Q, the Company, under the supervision, and with the participation, of its management, including its principal executive officer and principal financial officer, performed an evaluation of the design and operation of the Company's disclosure controls and procedures (as defined in Securities and Exchange Act Rule 13a-14(c)). Based on that evaluation, the Company's principal executive officer and principal financial officer concluded that such disclosure controls and procedures are effective to ensure that material information relating to the Company, including its consolidated subsidiaries, is accumulated and communicated to the Company's management and made known to the principal executive officer and principal financial officer, particularly during the period for which this periodic report was being prepared.

(b)  Changes in Internal Controls

     No significant changes were made in the Company's internal controls or in other factors that could significantly affect these controls subsequent to the evaluation described in Item 4(a).

 

PART II  Other Information

Items 1, 2, 3, 4 and 5 are not applicable and have been omitted.

 

Item 6.  Exhibits and Reports on Form 8-K

(a)           Exhibits

99.1              Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.2              Certification Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(b)                Reports on Form 8-K

                     The Company filed a Form 8-K on January 8, 2003 announcing that Gary K. Wright had been elected to serve on its
                     Board of   Directors.

                     The Company filed a Form 8-K on May 8, 2003 announcing it issued a press release regarding its financial results
                     for the three months ended March 31, 2003.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant
has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
PENN VIRGINIA CORPORATION
Date:	May 9, 2003				By:	/s/ Frank A. Pici
						Frank A. Pici
						Executive Vice President and
						Chief Financial Officer
Date:	May 9, 2003				By:	/s/ Dana G Wright
						Dana G Wright, Vice President and
						Principal Accounting Officer

 

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CERTIFICATIONS

 

I, A. James Dearlove, President and Chief Executive Officer of Penn Virginia Corporation (the "Registrant"), certify that:

1.        I have reviewed this quarterly report on Form 10-Q of the Registrant;

2.        Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact
           necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with
           respect to the period covered by this quarterly report;

3.        Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all
           material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in
           this quarterly report;

4.        The Registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
            (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and we have:

           a) designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including
                its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which
                this quarterly report is being prepared;