UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 20022003

Commission File Number 0-753

PENN VIRGINIA CORPORATION

OneThree Radnor Corporate Center, Suite 200230

100 Matsonford Road

Radnor, PA 19087

Registrant’s telephone number, including area code: (610) 687-8900

Securities registered pursuant to section 12(b) of the Act:

None

Securities Registered pursuant to Section 12(g) of the Act:

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

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  x¨

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

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. $348,612,796.$386,346,400.

As of February 27, 2003, 8,947,418March 4, 2004, 9,114,277 shares of common stock of the registrant were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

Penn Virginia Corporation and SubsidiariesPENN VIRGINIA CORPORATION AND SUBSIDIARIES

drilled in an area, and the unitization or pooling of crude oil and natural gas properties. In addition, state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. The effect of these regulations is to limit the amounts of crude oil and natural gas we can produce from our wells, and to limit the number of wells or the locations at which we can drill.

5

Federal Energy Regulatory Commission. The Federal Energy Regulatory Commission (“FERC”) regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). In the past, the Federal government has regulated the prices at which oil and gas could be sold. The Natural Gas Wellhead Decontrol Act of 1989 (the “Decontrol Act”) removed all NGA and NGPA price and nonprice controls affecting producers’ wellhead sales of natural gas effective January 1, 1993. While sales by producers of their own natural gas production, and all sales of crude oil, condensate and natural gas liquids can currently be made at market prices, Congress could reenact price controls in the future.

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (“Order No. 636”), which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ salessale of gas. Also, Order No. 636 requires pipelines to provide open-access transportation on a basis that is equal for all gas supplies. Although Order No. 636 does not directly regulate gas producers like Penn Virginia, Corporation, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry. The courts have largely affirmed the significant features of Order No. 636 and numerous related orders pertaining to the individual pipelines, although certain appeals remain pending and the FERC continues to review and modify its open access regulations. In particular, the FERC has issued Order No.Nos. 637, 637-A and 637-B which, among other things, (i) permitspermit pipelines to charge different maximum cost-based rates for peak and off-peak times,periods, (ii) encouragesencourage auctions for pipeline capacity, (iii) requiresrequire pipelines to implement imbalance management services, and (iv) restrictsrestrict the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders. In addition, the FERC has implemented regulations governingin place that govern the procedure for obtaining authorization to construct new pipeline facilities and has issued a policy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of newnewly constructed pipeline facilities to charge rates based solely on the incremental costs associated with such new pipeline facilities.

While any additional FERC action on these matters would affect us only indirectly, these changes are intended to further enhance competition in natural gas markets. We cannot predict what further action the FERC will take on these matters, nor can we predict whether the FERC’s actions will achieve its stated goal of increasing competition in natural gas markets. However, we do not believe that we will be treated materially differently than other natural gas producers and markets with which we compete.

Environmental Matters. Extensive federal, state and local laws govern oil and natural gas operations, regulate the discharge of materials into the environment or otherwise relate to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws that are often difficult and costly to comply with and which carry substantial administrative, civil and even criminal penalties for failure to comply. Some laws, rules and regulations relating to protection of the environment may, in certain circumstances, impose “strict liability” for environmental contamination, rendering a person liable for environmental and natural resource damages and cleanup costs without regard to negligence or fault on the part of such person. Other laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise exist or even prohibit exploration or production activities in sensitive areas. In addition, state laws often require some form of remedial action to prevent pollution from former operations, such as closure of inactive pits and plugging of abandoned wells. The regulatory burden on the oil and natural gas industry increases its cost of doing business and consequently affects its profitability. These laws, rules and regulations affect our operations, as well as the oil and gas exploration and production industry in general. We believe that we are in substantial compliance with current applicable environmental laws, rules and regulations and that continued compliance with existing requirements will not have a material adverse impact on us. Nevertheless, changes in existing environmental laws or the adoption of new environmental laws have the potential to adversely affect our operations.

Page 86

Coal Royalty and Land Management

Although the Partnership intendsexpects to make quarterly cash distributions of $0.52 or more per common unit, it can only do so to the extent it has sufficient cash from operations after payment of fees and expenses. In addition, quarterly distributions are payable on our subordinated units only after each common unit has received a distribution of $0.52$0.50 plus any arrearages due from prior quarters. Incentive distributions are payable to our general partner subsidiary after cash distributions per unit exceed $0.55 in any quarter. The Partnership’s revenues and its ability to make quarterly and incentive distributions are subject to several risks, including those described below.

Competition

The coal industry is intensely competitive primarily as a result of the existence of numerous producers. The Partnership’s lessees compete with coal producers in various regions of the U.S. for domestic sales. The industry has undergone significant consolidation that has led to some of the competitors of the Partnership’s lessees located in Appalachia to have significantly larger financial and operating resources than the Partnership’s lessees do. The Partnership’s lessees primarily compete with both large and small producers in Appalachia as well as the western United States. They compete on the basis of coal price at the mine, coal quality (including sulfur content), transportation cost from the mine to the customer and the reliability of supply. Continued demand for the Partnership’s coal and the prices that the Partnership’s lessees obtain are also affected by demand for electricity, environmental and government regulations, technological developments and the availability and price of alternative fuel supplies, including nuclear, natural gas, oil and hydroelectric power. Demand for the Partnership’s low sulfur coal and the prices the Partnership’s lessees will be able to obtain for it will also be affected by the price and availability of high sulfur coal, which can be marketed in tandem with emissions allowances in order to meet federal Clean Air Act requirements.

Operating Risks

General Regulation. The Partnership’s lessees are obligated to conduct mining operations in compliance with all applicable federal, state and local laws and regulations. These laws and regulations include matters involving the discharge of materials into the environment, employee health and safety, mine permits and other licensing requirements, reclamation and restoration of mining properties after mining is completed, management of materials generated by mining operations, surface subsidence from underground mining, water pollution, legislatively mandated benefits for current and retired coal miners, air quality standards, protection of wetlands, plant and wildlife protection, limitations on land use, storage of petroleum products and substances which are regarded as hazardous under applicable laws, and management of electrical equipment containing polychlorinated biphenyls, or PCBs. Because of extensive and comprehensive regulatory requirements, violations during mining operations are not unusual in the industry and, notwithstanding compliance efforts, we do not believe violations by the Partnership’s lessees can be eliminated completely. However, none of the violations to date, or the monetary penalties assessed, have been material to us, to the Partnership or, to our knowledge, to the Partnership’s lessees. We do not currently expect that future compliance will have a material adverse effect on us or the Partnership.

While it is not possible to quantify the costs of compliance by the Partnership’s lessees with all applicable federal and state laws, those costs have been and are expected to continue to be significant. The lessees post performance bonds pursuant to federal and state mining laws and regulations for the estimated costs of reclamation and mine closing, including the cost of treating mine water discharge when necessary. The Partnership does not accrue for such costs because its lessees are contractually liable for all costs relating to their mining operations, including the costs of reclamation and mine closure. However, the Partnership does require some smaller lessees to deposit certain funds into escrow for reclamation and mine closure costs or post performance bonds for these costs. Although the lessees typically accrue adequate amounts for these costs, their future operating results wouldmight be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

7

In addition, the electric utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for the Partnership’s lessees’ coal. 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 the Partnership, its lessees or their customers to change operations significantly or incur substantial costs.

Page 9

RegulationCertain Regulatory and Legal Matters.

Clean Air Act. The Clean Air Act affects the end-users of coal and could significantly affect the demand for the Partnership’s coal and reduce the Partnership’s coal royalty revenues. The Clean Air Act and corresponding state and local laws extensively regulate the amount of sulfur dioxide, particulate matter, nitrogen oxides and other compounds emitted from industrial boilers and power plants, including those that use the Partnership’s coal. These regulations together constitute a significant burden on coal customers and stricter regulation could further adversely impact the demand for and price of the Partnership’s coal, resulting in lower coal royalty revenues.

In July 1997, the U.S. Environmental Protection Agency (“EPA”) adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. Details regarding the new particulate standard itself are still subject to judicial challenge. These ozone restrictions will require electric power generators to further reduce nitrogen oxide emissions. Nitrogen oxides are naturally occurring byproducts of coal combustion that lead to the formation of ozone. Further reduction in the amount of particulate matter that may be emitted by power plants could also result in reduced coal consumption by electric power generators. Future regulations regarding ozone, particulate matter and other ambient air standards could restrict the market for coal and the development of new mines by the Partnership’s lessees. This in turn may result in decreased production by the Partnership’s lessees and a corresponding decrease in the Partnership’s coal royalty revenues. These decreases could adversely effectaffect the distributions we receive from the Partnership.

The Clean Air Act also imposes standards on sources of hazardous air pollutants. These standards have not yet been extended to coal mining operations, or by-productsbut in January 2004, EPA proposed regulations to control emissions of coal combustion, but consideration is now being given to regulating certainmercury, a hazardous air pollutant componentsfrom power plants that combust coal, as well as nitrogen oxides and sulfur dioxide, which are found in coal combustion exhaust, including mercury.also power plant pollutants, Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.

Surface Mining Control and Reclamation Act of 1977. The Surface Mining Control and Reclamation Act of 1977 (“SMCRA”) and similar state statutes impose on mine operators the responsibility of restoring the land to its original state or compensating the landowner for types of damages occurring as a result of mining operations, and require mine operators to post performance bonds to ensure compliance with any reclamation obligations. Regulatory authorities may attempt to assign the liabilities of the Partnership’s lessees to the Partnership if any of the lessees are not financially capable of fulfilling those obligations. In conjunction with mining the property, the Partnership’s lessees are contractually obligated under the terms of their leases to comply with all laws, including SMCRA and equivalent state and local laws, which obligations include reclaiming and restoring the mined areas by grading, shaping and reseeding the soil. Upon completion of the mining, reclamation generally is completed by seeding with grasses or planting trees for use as pasture or timberland, as specified in the approved reclamation plan.

CERCLA. The Partnership could become liable under federal and state Superfund and waste management statutes if its lessees are unable to pay environmental cleanup costs. The Comprehensive Environmental Response, Compensation and Liability Act, known as CERCLA or “Superfund,” and similar state laws create liabilities for the investigation and remediation of releases and threatened releases of hazardous substances to the environment and damages to natural resources. As a landowner, the Partnership is potentially subject to liability for these investigation and remediation obligations.

8

Mountaintop Removal LitigationSurface Mining Valley Fills.. On January 29, 2003, Over 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 officecourse of the U.S. Army Corpslast several years, opponents of Engineers (the “Corps”) from issuingsurface mining have filed three lawsuits challenging the legality of permits under Section 404 of the Clean Water Act forauthorizing the construction of valley fills for the disposal of coal mining overburden. These valleys typically contain steamsoverburden under federal and state laws applicable to surface mining activities. Although two of these challenges were successful in the United States District Court for the southern District of West Virginia (the “District Court”), the United States Court of Appeals for the Fourth Circuit overturned both of those decisions in Bragg v. Robertson in 2001 and in Kentuckians For The Commonwealth v. Rivenburgh in 2003.

On October 23, 2003, a third lawsuit involving the disposal of coal mining overburden was filed under the name of Ohio Valley Environmental Coalition v. Bulen. In this case, which was also filed in the District Court, several public interest group plaintiffs have alleged that underthe Army Corps of Engineers violated 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(“CWA”) and other federal regulations when it issued Nationwide Permit 21, a violation of the Clean Water Act since Section 404 allows only the permitting of fill material depositedgeneral permit for a beneficial purpose and not for mere waste disposal such as the disposal of coal overburden. The Circuit Court reversedmining overburden into United States waters. This most recent suit also challenges certain individual discharge authorizations in West Virginia, including several involving the mining activities of the Partnership’s lessees. If the plaintiffs prevail in this finding, concluding, instead, that overburden valley fillslatest lawsuit, lessees who have received authorization for discharges pursuant to Nationwide Permit 21 could be prevented from undertaking future discharges until they receive individual CWA permits, and future operations could require individual permits. Obtaining these individual permits is likely to substantially increase both the time and the costs of obtaining CWA permits for our lessees and other coal mining operators throughout the industry where any such unfavorable ruling may be permitted under Section 404 and remandedapplied. These increases could adversely affect our coal royalty revenues. Although the case backPartnership expects that any ruling for the plaintiffs would be appealed to the Fourth Circuit, the coal mining industry, including the operations of our lessees, could be significantly adversely impacted by the initial effects of an adverse decision while any appeal is pending.

West Virginia Anti-degradation Policy.As a result of a September 2003 decision by the District Court for further proceedingsin Ohio Valley Environmental Coalition v. Whitman, the State of West Virginia is currently implementing the CWA without an EPA-approved anti-degradation implementation policy, which would apply in cases of pollutant discharges into waters that have been designated as high quality waters by the State. In this case, the District Court vacated EPA’s previous approval of the West Virginia anti-degradation policy after the District Court determined that the State’s policy did not inconsistentcomply with the Circuit Court’s opinion.requirements of the CWA. The West Virginia anti-degradation policy had included a number of exceptions, including one for parties holding general CWA permits, from anti-degradation review requirements. The EPA has reportedly decided not to appeal this decision and is instead proceeding with a policy review. Were PVA’s lessees to seek permits to discharge coal overburden into high quality waters under a new policy which does not include such an exception, permit applications will likely be required to undergo the public and intergovernmental scrutiny associated with an anti-degradation review, which may either delay the issuance or reissuance of CWA permits, require the use of more costly control measures or lead to the denial of these permits. The delay, denial or added costs of complying with these permits may increase the costs of coal production, potentially reducing PVR’s royalty revenues and adversely affecting our Partnership distributions.

Mine Health and Safety Laws.Stringent safety and health standards have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. The Mine Health and Safety Act of 1969 resulted in increased operating costs and reduced productivity. The Mine Safety and Health Act of 1977, which significantly expanded the enforcement of health and safety standards of the Mine Health and Safety Act of 1969, imposes comprehensive safety and health standards on all mining operations. In addition, as part of the Mine Health and Safety Acts of 1969 and 1977, the Black Lung Acts require payments of benefits by all businesses conducting current mining operations to coal miners with black lung and to some survivors of a miner who dieshas died from this disease.

Page 10

Mining Permits and Approvals.Numerous governmental permits or approvals are required for mining operations. In connection with obtaining these permits and approvals, the Partnership’s lessees may be required to prepare and present to federal, state or local authorities data pertaining to the effect or impact that any

9

proposed production of coal may have upon the environment. The requirements imposed by any of these authorities may be costly and time consuming and may delay commencement or continuation of mining operations.

In order to obtain mining permits and approvals from state regulatory authorities, mine operators, including the Partnership’s lessees, must submit a reclamation plan for restoring, upon the completion of mining operations, the mined property to its prior condition, productive use or other permitted condition. Typically, lessees submit the necessary permit applications between 12 and 18 months before they plan to begin mining a new area. In the Partnership’s experience, permits generally are approved within 12 months after a completed application is submitted. In the past, lessees have generally obtained their mining permits without significant delay. The Partnership’s lessees have obtained or applied for permits to mine a majority of the reserves that are currently planned to be mined by lesseesthem over the next five years. The Partnership’s lessees are also in the planning phase for obtaining permits for the remainingadditional reserves planned to be mined over the nextfollowing five years. However, they cannot makegive any assurances that they will not experience difficulty in obtaining mining permits in the future.

Timber Regulations.The Partnership’s timber operations are subject to federal, state and local laws and regulations, including those related to the environment, protection of endangered species, foresting activities and health and safety. The Partnership believes it is managing its timberlands in substantial compliance with applicable federal and state regulations.

Employees

We had 104116 employees at December 31, 2002,2003, including 3032 employees who directly provide services for PVR through its general partner. We consider our relations with our employees to be good.

Available Information

The Company’s Internet address is www.pennvirginia.com. We make available free of charge on or through our Internet website our Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and the charters of each of our Audit Committee, Nominating and Governance Committee, Compensation and Benefits Committee and Oil and Gas Committee. We also make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission. To date, we have inadvertently not made so available on our website any current reports on Form 8-K. We will provide, free of charge upon request, electronic or paper copies of all current reports on Form 8-K which were filed from November 15, 2002 to February 15, 2003. We will make available, free of charge, on or through our internet website, all reports on Form 8-K and amendments to those reports filed after February 15, 2003 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the Securities and Exchange Commission.

Page 11

Executive Officers of the Company

The following table sets forth information concerning our executive officers. Each officer is elected annually by the Board of Directors and serves at the pleasure of the Board of Directors.

10

A. James Dearlove – Dearlove—Mr. Dearlove has served in various capacities with the Company since 1977, including as President and Chief Executive Officer and a Director of the Company since May 1996, President and Chief Operating Officer of the Company from 1994 to May 1996, Senior Vice President of the Company form 1992 to 1994 and Vice President of the Company from 1986 to 1992. He is also Chief Executive Officer and Chairman of the Board of Penn Virginia Resource GP, LLC, the general partner of Penn Virginia Resource Partners, L.P. He also serves as director of the Powell River Project and the National Council of Coal Lessors.

Frank A. Pici – Pici—Mr. Pici is the Executive Vice President and Chief Financial Officer of the Company, which he joined in September 2001. Mr. Pici is also the Vice President and Chief Financial Officer and a Director of Penn Virginia Resource, GP LLC. From 1996 to August 2001, Mr. Pici was Vice President of Finance and Chief Financial Officer of Mariner Energy, Inc., an oil and gas exploration and production company. Prior to 1996, he served in various capacities with Cabot Oil & Gas Corporation, including Corporate Controller from 1994 to 1996, Director, Internal Audit from 1992 to 1994, and regional accounting manager from 1989 to 1992. From 1982 to 1989, he held financial management positions with companies in the oil and gas and coal industries.

Keith D. Horton – Mr. Horton has served in various capacities with the Company since 1981, including Executive Vice President and a Director of the Company since December 2000, Vice President – Eastern Operations of the Company from May 1996 to May 1997, President of Penn Virginia Coal Company from April 1996 to October 2001, Vice President of Penn Virginia Coal Company from March 1994 to February 1996, Vice President from January 1990 to December 1998, and Manager, Coal Operations from July 1982 to December 1989, of Penn Virginia Resources Corporation. He is also the President and Chief Operating Officer and a Director of Penn Virginia Resource, GP LLC. Additionally, Mr. Horton is Chairman of the Central Appalachian Section of the Society of Mining Engineers. He also serves as a director of the Virginia Mining Association, Powell River Project and Virginia Coal Council.

H. Baird Whitehead – Whitehead—Mr. Whitehead is an Executive Vice President of the Company, which he joined in January 2001. Prior to joining Penn Virginia, Mr. Whitehead served in various positions with Cabot Oil & Gas Corporation. From 1998 to 2001, he served as Senior Vice President during which time he oversaw Cabot’s drilling, production, and exploration activity in the Appalachia, Rocky Mountains, Mid-Continent and the Texas and Louisiana Gulf Coast areas. From 1992 to 1998, he was Vice President and Regional Manager of Cabot’s Appalachian business unit and from 1989 to 1992, he was Vice President and Regional Manager of Cabot’s Anadarko business unit. From 1987 to 1989, he served as Vice President of Engineering for Cabot. From 1972 to 1987, he held various engineering and supervisory positions with Texaco, Columbia Gas Transmission and Cabot.

Keith D. Horton—Mr. Horton has served in various capacities with the Company since 1981, including Executive Vice President and a Director of the Company since December 2000, Vice President—Eastern Operations of the Company from February 1999 to December 2000, President of Penn Virginia Coal Company from February 1996 to October 2001, Vice President of Penn Virginia Coal Company from March 1994 to February 1996, Vice President from January 1990 to December 1998, and Manager, Coal Operations from July 1982 to December 1989, of Penn Virginia Resources Corporation. He is also the President and Chief Operating Officer and a Director of Penn Virginia Resource, GP LLC. Additionally, Mr. Horton is Chairman of the Central Appalachian Section of the Society of Mining Engineers. He also serves as a director of the Virginia Mining Association, Powell River Project and Virginia Coal Council.

Nancy M. Snyder – Snyder—Ms. Snyder has served as Senior Vice President of the Company since February 2003 as Vice President since December 2000 and as General Counsel and Corporate Secretary of the Company since 1997. She was a Vice President of the Company from December 200 to February 2003. Ms. Snyder is also the Vice President, General Counsel and a Director of Penn Virginia Resource GP, LLC. From 1993 to 1997, Ms. Snyder was a solo practitioner representing clients generally in connection with mergers and acquisitions and general corporate matters. From 1990 to 1993, Ms. Snyder served as general counsel to Nan Duskin, Inc. and its affiliated companies, which were in the businesses of womens’women’s’ retail fashion and real estate. From 1983 to 1989, Ms. Snyder was an associate at the law firm of Duane Morris, where she practiced securities, banking and general corporate law.

Dana G. Wright – G Wright—Mr. Wright joined the Company in July 2002 and serves as Vice President and Controller. Prior to joining Penn Virginia, he was employed for 26 years with Atlantic Richfield Company, and most recently with its publicly traded subsidiary, Vastar Resources, Inc. During that time he held a variety of financial, accounting and treasury related positions.

Ronald K. Page—Mr. Page 12has served as Vice President, Corporate Development since joining the Company in July 2003. From January 1998 to May 2003, Mr. Page served in various positions with El Paso Field Services Company, including Vice President of Commercial Operations—Texas Pipelines and Processing, Vice

11

President of Business Development, Director of Business Development and Consultant. From October 1995 through December 1997, Mr. Page was employed as Vice President of Business Development by TPC Corporation (formerly Texas Power Corporation). For 17 years prior to 1995, Mr. Page served in various positions at Seagull Energy Corporation, including Vice President of Operations at Seagull’s Enstar Natural Gas Company, Vice President of Pipelines and Marketing and Manager of Engineering.

The following terms have the meanings indicated below when used in this report.

12

Page 13

ITEM 2 –PROPERTIESItem 2—Properties

Facilities

We are headquartered in Radnor, Pennsylvania with additional offices in Kingsport, Tennessee, Houston, Texas and Charleston, West Virginia. All of our office facilities are leased. We believe that our properties are adequate for our current needs.

Title to Properties

We believe that we have satisfactory title to all of our properties and the associated oil and gas reserves in accordance with standards generally accepted in the oil and natural gas and coal royalty and land management industries.

As is customary in the oil and gas industry, we make only a cursory review of title to farmout acreage and to undeveloped oil and gas leases upon execution of any contracts. Prior to the commencement of drilling operations, a thorough title examination is conducted and curative work is performed with respect to significant defects. To the extent title opinions or other investigations reflect defects, we cure such title defects. If we were unable to remedy or cure any title defect of a nature such that it would not be prudent to commence drilling operations on a property, we could suffer a loss of our investment in the property. Prior to completing an acquisition of producing oil and gas assets, we obtain title opinions on all material leases. Our oil and gas properties are subject to customary royalty interests, liens for current taxes and other burdens that we believe do not materially interfere with the use or materially affect the value of such properties.

Of the 615588 million tons of proven and probable coal reserves to which the Partnership hashad rights as of December 31, 2002,2003, PVR owned the mineral rightsinterests and the majority of related surface rights to 572544 million tons, or 93 percent, and leased the remaining 4344 million tons, or 7 percent, from unaffiliated third parties. In addition to the revenues the Partnership receives from its coal business, it also earns revenues from the sale of timber. At December 31, 2002, the Partnership owned 114,500 surface acres of timberland containing 168 million board feet of inventory.

Page 1413

Information Regarding Oil and Gas Properties

Production and Pricing

The following table sets forth production, average sales prices and production costs with respect to our properties for the years ended December 31, 2003, 2002 2001 and 2000.2001.

*Production for 2002 does not include approximately 16 Mbbls of oil condensate and 18 MMcf of natural gas production, or 114 MMcfe, related to discontinued operations. 2001 production volumes for properties sold were insignificant.

Page 1514

Proved Reserves

We hadThe following table presents certain information regarding our proved reserves as of 241 BcfDecember 31, 2003, 2002 and 2001. The proved reserve estimates presented below were prepared by Wright and Company, Inc., independent petroleum engineers. For additional information regarding estimates of natural gasproved reserves, the preparation of such estimates by Wright and 5.4 million barrels of crudeCompany, Inc. and other information about our oil and condensate at December 31, 2002. The present valuegas reserves, see Note 23. Supplemental Information on Oil and Gas Producing Activities (Unaudited) of the estimated future cash flows discounted at 10 percent (pre-tax SEC PV10 Value) at December 31, 2002, was $481 million. At December 31, 2002, we had 195 gross (128.3 net)Notes to the Consolidated Financial Statements. Our estimates of proved undeveloped drilling locations.reserves in the table above are consistent with those filed by us with other federal agencies.

The standardized measure of discounted future net cash flows, which represents the present value of future net revenues after income taxes discounted at ten percent, was $512 million, $355 million and $189 million and $467 million atas of December 31, 2003, 2002 2001 and 2000,2001, respectively. For information on the changes in standardized measure of discounted future net cash flows. Seeflows, see Note 22 (Supplementary23. Supplemental Information on Oil and Gas Producing Activities (Unaudited)) of the Notes to the Consolidated Financial Statements, for more information.Statements.

In accordance with the Securities and Exchange Commission’s guidelines, the engineers’ estimates of future net revenues from our properties and the pre-tax SEC PV10 value thereof are made using oil and natural gas sales prices in effect as of December 31, 2002.2003. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Net proved oil and gas reserves for the three years ended December 31, 2002 were estimated by Wright and Company, Inc. Prices for oil and gas are subject to substantial seasonal fluctuations and prices for each are subject to substantialas well as fluctuations as a result ofresulting from numerous other factors. See Item 7 – 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Proved reserves are the estimated quantities of natural gas, crude oil and condensate 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 proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond our control. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The quantities of crude oil and natural gas

15

that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, neither the pre-tax nor after-tax SEC PV10 value amounts shown above should not be

construed as the current market value of the estimated oil and natural gas reserves attributable to our properties. The information set forth in the foregoing tables includes revisions of certain volumetric reserve estimates attributable to proved properties included in the preceding year’s estimates. Such revisions are the result of additional information from subsequent completions and production history from the

Page 16

properties involved or the result of a decrease (or increase) in the projected economic life of such properties resulting from changes in production prices.

Acreage

The following table sets forth our developed and undeveloped acreage at December 31, 2002.2003. The acreage is located in the eastern and southern portionsGulf Coast areas of the United States.

Wells Drilled

The following table sets forth the gross and net number of exploratory and development wells drilled during the last three years. The number of wells drilled refers to the number of wells spud at any time during the respective year. Net wells equal the number of gross wells multiplied by our working interest in each of the gross wells. Productive wells represent either wells which were producing or which were capable of commercial production.

The ten exploratory wells under evaluation represent coalbed methane (“CBM”) wells drilled and completed in the Cherokee Basin in Chase County, Kansas. The Company expects to determine the commercial viability of the Cherokee basin program during the first half of 2004.

16

Productive Wells

The number of productive oil and gas wells in which we had a working interest at December 31, 20022003 is set forth below. Productive wells are producing wells or wells capable of commercial production.

In addition to the above working interest wells, Penn Virginia owns royalty interests in 2,346 gross wells.

Page 17

Information Regarding Coal Royalty and Land Management Properties

The Partnership’s coal reserves at December 31, 20022003 covered 241,000 acres, including fee and leased acreage, in Virginia, West Virginia, New Mexico and eastern Kentucky. The coal reserves are in various surface and underground seams.

The Partnership’s As of December 31, 2003, the Partnership had approximately 588 million tons of proven and probable coal reserves, which are estimated at 615 million tons as of December 31, 2002. found in the following six separate properties:

Reserves are coal tons that can be economically extracted or produced at the time of determination considering legal, economic and technical limitations. Proven coal reserves are reserves for which (a) the quantity is computed from dimensions revealed in outcrops, trenches, working or drill holes; grade and/orand quality are computed from the results of detailed sampling; and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well defined,well-defined, that the size, shape, and depth and mineral content of reserves are well-established. Probable coal reserves are reserves for which quantity and grade and/or quality are computed from information similar to that used for proven reserves, but the sites for inspection, sampling and measurement are farther apart or are otherwise less adequately spaced. The degree of assurance, although lower than that for proven reserves, is high enough to assume continuity between points of observation.

In areas where geologic conditions indicate potential inconsistencies related to coal reserves, the Partnership performs additional drilling to ensure the continuity and mineablility of coal reserves. Consequently, sampling in those areas involves drill holes that are spaced closer together than those distances cited above.

Reserve estimates are adjusted annually for production, unmineable areas, acquisitions and sales of coal in place. The majority of PVR’s reserves are high in energy content, low in sulfur and suitable for either the steam or metallurgical markets.market.

The amount of coal a lessee can profitably mine at any given time is subject to several factors and may be substantially different from “proven and probable reserves.” Included among the factors that influence profitability are the existing market price, coal quality and operating costs.

17

The following table sets forth production data and reserve information with respect to each of the Partnership’s six properties:

The following table sets forth the coal reserves the Partnership owns and leases with respect to each of its coal properties as of December 31, 2003:

At December 31, 2003, the Partnership’s coal reserve estimates were prepared from geological data assembled and analyzed by PVR’s general partner’s geologists and engineers. These estimates were compiled using geological data taken from thousands of drill holes, adjacent mine workings, outcrop prospect openings and other sources. These estimates also take into account legal, qualitative technical and economic limitations that may keep coal from being mined. Reserve estimates will change from time to time due to mining activities, analysis of new engineering and geological data, acquisition or divestment of reserve holdings, modification of mining plans or mining methods and other factors

The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. At December 31, 2002,2003, the Partnership owned an estimated 168166 MMbf of standing saw timber.

ITEM 3 –LEGAL PROCEEDINGSItem 3—Legal Proceedings

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

ITEM 4 –SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERSItem 4—Submission of Matters to a Vote of Security Holders

There were no matters submitted to a vote of security holders during the fourth quarter of 2002.2003.

Page 18

PART II

ITEM 5 –MARKET FOR THE COMPANY’S COMMON STOCK AND RELATED STOCKHOLDER MATTERSItem 5—Market for the Company’s Common Stock and Related Stockholder Matters

Common Stock Market Prices And Dividends

High and low closing stocksales prices and dividends for the last two years were:

The Company’s common stock is traded on the New York Stock Exchange under the symbol PVA.

Page 19

ITEM 6 –SELECTED FINANCIAL DATAItem 6—Selected Financial Data

Five Year Selected Financial Data

Page 2019

ITEM 7 –MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSItem 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following reviewanalysis of operationsfinancial condition and financial conditionresults 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 producessells 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 44.5 percent ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a Delaware limited partnership, see Note 2 (Penn. Penn Virginia Resource Partners, L.P.)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 Notesgeneral 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:

As a result of our ownership in the Partnership, we receive cash payments from PVR in the form of quarterly cash distributions. We received approximately $16.8 million of cash distributions from PVR during 2003. As part of our ownership of PVR’s general partner, we also own the rights, referred to the Consolidated Financial Statements.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. See Item 1—Business—Corporate and Other for more information on incentive distribution rights. As of December 31, 2003, PVR had not achieved a level of distribution 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 intendexpect to execute a program combining relatively low risk, moderate return development drilling in the eastAppalachian 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

20

expanding our eastern presence by developing coalbed methane (“CBM”) gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to increase production ratesthe value from coalbed methanethe CBM reserves we own. We are also committed to expanding our onshore Gulf Coast oil and gas reserves and production internally through our exploratory and development drilling programprograms and by acquiring reserves with favorable return potential.returns.

In 2002, these efforts resulted in a 47 percentthe coal royalty and land management segment, PVR continually evaluates acquisition opportunities that could increase in oilto 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 gas production from 2001, and we expect an increase in 2003 oil and gas production of at least 30 percent, with a corresponding increase in operating cash flow. In January 2003, we completed an acquisition of approximately 31.8 Bcfe of proved reserves, in the South Texas area of the onshore Gulf Coast regionacquiring or constructing assets for $32.5 million,coal services which willwould provide a significant part offee-based revenue stream and acquiring mid-stream hydrocarbon-related transportation assets and other operating units that would strategically fit within the expected growth in 2003 production.Partnership.

Our oil and gas capital expenditures for 2003, including the January 2003 South Texas acquisition,2004 are expected to be $110 to $120approximately $100 million. Borrowings against our $140 million credit facility were $16$64 million out of $150 million available as of December 31, 2002,2003, and we expect to fund our 20032004 capital expenditures with a combination of internal cash flow and credit facility borrowings.

During 2002, PVR completed its first two coal reserve acquisitions since its initial public offering in October 2001. In December 2002, PVR announced the formation of a strategic alliance with Peabody, resulting from the purchase from and leaseback to Peabody of approximately 120 million tons of coal reserves in New Mexico and northern West Virginia for $72.5 million in cash and a total of 2.76 million common units and Class B common units. The Peabody Acquisition significantly expanded PVR’s geographic diversity and included incentives for Peabody to source additional assets to the Partnership in the future. In August 2002, PVR also purchased approximately 16 million tons of coal reserves in northern West Virginia for $12.0 million. The two acquisitions are expected to contribute 12.3 million to 12.9 million tons of production and $16.5 million to $17.5 million of cash flow from operations to PVR in 2003.

Coal-related capital expenditures on existing properties in 20032004 are expected to be $3.0 to $3.3 million for the construction of new coal service-related projects for which PVR will collect a fee.less than $0.5 million. As of December 31, 2002,2003, PVR had borrowed $90.9$91.8 million against its credit facility, and it is currently attempting to refinance those borrowings with a more permanent form of debt. The Partnership expects to complete the refinancing during the first quarter of 2003.debt facilities. Cash flow from operations, supplemented with credit facility borrowings, areis expected to be adequate for PVR to fund 20032004 capital expenditures and distributions to unitholders.

2003 Performance—Oil and Gas Segment

In 2003, we increased our oil and gas production to 23.8 Bcfe, a 14 percent increase over 20.8 Bcfe produced in 2002. This increase resulted from a January 2003 acquisition in south Texas, the Company’s horizontal CBM drilling program in central Appalachia and additional drilling of the Selma Chalk wells in Mississippi. These increases were offset in part by natural field declines. Average daily oil and gas production increased to 67.1 MMcfe in the fourth quarter of 2003 compared to 57.8 MMcfe in the fourth quarter of 2002.

Commodity prices, in particular for natural gas, were the largest single factor affecting our financial results in 2003. Price volatility in the natural gas market has been high in the last few years. Throughout 2002 and 2003, the NYMEX futures market reported unprecedented natural gas contract prices. Our realized natural gas price in 2003 was $5.31 per Mcf, net of $0.28 per Mcf hedging loss. We use financial instruments to hedge natural gas and, to a lesser extent, oil prices. The use of financial hedging instruments is an integral part of our risk management strategy, but in 2003 we realized a lower price per Mcf as a result of hedging.

Our total oil and gas reserves at the end of 2003 were 323 Bcfe, an increase of 18 percent over 2002. Approximately 88 percent of our reserves at year-end 2003 were natural gas. We replaced 308 percent of our production during 2003 at a reserve replacement cost of $1.81 per Mcfe. We drilled a total of 180 gross (132.1 net) wells during 2003, including 162 gross (118.0 net) development wells with a 99 percent success rate, and 18 gross (14.1 net) exploratory wells with a success rate of 63 percent.

During 2003, we continued to expand our CBM production and reserve base in central Appalachia through acquisitions and the use of a proprietary horizontal drilling technology owned by CDX Gas, LLC (“CDX”). Under our agreement with CDX, we have the right to use the technology to drill CBM wells in a 16,000 square mile area of mutual interest (AMI) covering virtually all of central Appalachia. We acquired over 131,000 acres during 2003 and now own over 619,000 acres of CBM-prospective leasehold within the AMI. By greatly accelerating production from these heretofore long-lived reserves, we believe that this drilling technique should result in superior rates of return, with very low geological risk. This technique was used to drill and complete 12 gross (4.6 net) horizontal CBM wells during 2003, more than doubling our horizontal CBM production to 1.1 Bcfe from 0.5 Bcfe in 2002. In 2004, our capital budget includes $20 million to continue to develop horizontal CBM reserves in central Appalachia and to build additional pipeline infrastructure to transport the additional production, which is expected to become an increasingly significant part of our production base.

21

We are also conducting a conventional CBM pilot project in the Cherokee Basin of southeastern Kansas, where we control over 40,000 acres of potentially prospective CBM property, and we expect to know by mid-2004 whether this project is commercially viable.

We continued to employ a low-risk development strategy in our other core areas during 2003. In Appalachia, we drilled 54 gross (31.2 net) conventional wells. In Mississippi, we drilled 77 gross (75.7 net) wells and acquired new Selma Chalk acreage to complement existing positions, adding to this area two to three more years of potential low-risk drilling locations. Our 2004 budget includes approximately $13 million to drill 57 gross (44 net) development wells in Appalachia and Mississippi. In early 2003, we also acquired a combination of proved producing and proved undeveloped reserves in Kingsville, a south Texas field. We participated in the drilling of 11 wells to partially develop the field. In December 2003, we entered into a joint venture giving us access to a potentially large number of low-risk, long-lived development drilling locations in over 17,000 acres in the Cotton Valley play of east Texas. We are also active on the Louisiana side of the Cotton Valley play. We expect to spend approximately $14 million to drill and operate as many as 18 gross (10.5 net) wells in the east Texas / north Louisiana corridor during 2004.

To balance the low risk portion of our portfolio with a number of higher risk, potentially higher reward projects, we expanded our drilling efforts along the Gulf Coast during 2003. We drilled a successful field extension well in the Broussard field in south Louisiana. We also drilled seven gross (3.1 net) exploratory wells in the Gulf Coast region, including five gross (1.2 net) successful exploratory wells in as many attempts in the Stella and south Creole fields in south Louisiana. Including follow-up development drilling, as of mid-January 2004, these fields were contributing over eight MMcfe, or more than ten percent of our total daily production. Approximately $25 million has been budgeted in 2004 to drill 22 gross (12 net) exploratory wells. We expect to drill a total of eight gross (four net) wells in our higher risk, higher impact Esperanza and Kingsville prospects in south Texas and our Bayou Sale prospect in south Louisiana. Lower and moderate risk projects comprise the remainder of the 2004 exploratory drilling budget and include new prospects in the south Creole, Stella and Fannett areas along the Gulf Coast, a southeastern Louisiana Miocene play and a new CBM prospect in northern West Virginia.

The ability to internally generate exploration and development prospects is important to our approach in maximizing value. Toward that goal, we continued to hire technically proficient professionals and to acquire seismic data and leaseholds during 2003. We have assembled a high quality staff of both internal and consulting explorationists, and late in 2003, we acquired access to 5,000 square miles of high quality 3-D seismic data along the onshore Gulf Coast areas of Texas and Louisiana, which will more than double our seismic data inventory over the next year. To support this effort, approximately 15 percent of our 2004 capital budget has been allocated to the acquisition of seismic data and new leaseholds.

2003 Performance—Coal Royalty and Land Management Segment (PVR)

In 2003, coal royalty revenues increased 60 percent to $50.3 million from $31.4 million in 2002. This increase was driven by an 85 percent increase in coal production from PVR properties to 26.5 million tons in 2003 from 14.3 million tons in 2002. This production increase was primarily due to the late 2002 acquisition of 120 million tons of coal reserves from Peabody Energy Corporation (“the Peabody Acquisition”), Production from the Peabody Acquisition-related properties contributed 10.6 million tons in 2003. The average royalty rate received for coal produced from these properties during 2003 was $1.33 per ton. Excluding the property acquired from Peabody, production in West Virginia increased 34 percent due to the start up of new mining operations on PVR’s Coal River property, including sub-leased operations on which PVR receives a relatively smaller margin per ton of coal mined. Tonnage mined from PVR’s Virginia properties was up approximately three percent in 2003 from 2002.

Coal prices, especially in central Appalachia where the majority of PVR’s production is located, have increased significantly since the beginning of 2003. The price increase stems from several causes including increased electricity demand and decreasing coal production in central Appalachia.

22

In May 2003, PVR agreed to a new lease on its West Coal River property (formerly known as Fork Creek) with an established operator, who has over 25 years of experience as a successful miner in Appalachia. Production from the idled property commenced in July 2003 and is expected to increase over the next couple of years.

PVR also collects fees and railroad rebates related to its ownership of the coal preparation plant and coal loading facility on the West Coal River property. This new facility and several smaller modular coal preparation plants are resulting in additional coal services revenues, supplementing revenues from the Shober loading facility in Virginia. PVR also spent approximately $4.0 million to construct a third large-scale coal loading facility on its Coal River property, which began operating in February 2004. Coal services revenues increased to $2.1 million in 2003 from $1.7 million in 2002, and are expected to increase further in 2004. PVR believes that these types of fee-based infrastructure assets provide exceptional investment and cash flow opportunities to the Partnership, and it continues to look for additional investments of this type and in other qualified, primarily fee-based assets, including oil and gas midstream assets.

As part of its coal land management business, PVR owns approximately 166 million board feet of standing timber. The Partnership typically sells cutting rights to various contractors who cut in advance of a mining project. Timber revenues in 2003 were $1.0 million, down from $1.6 million in 2002.

Critical Accounting Policies and Estimates

Oil and Gas Properties.We useThe process of preparing financial statements in accordance with Generally Accepted Accounting Principals (“GAAP”) requires 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.

Page 21

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, the costmanagement of the property has been impaired. As unproved leaseholds are determinedCompany to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be productive,recorded if these estimates and judgments change or if the related costs are transferred to proved leaseholds. As of December 31, 2002, we had approximately $57.6 million of unproved leasehold costs included in oilactual results differ from these estimates and gas properties on our consolidated balance sheet.judgments. We expect to complete an evaluation of our unproved leaseholds overconsider the next two to three years.

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 estimatedfollowing to be the expected present value of future net cash flows from proved reserves, discounted utilizing a risk-free interest rate commensurate withmost critical accounting policies which involve the remaining lives for the respective oil and gas properties.

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. 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 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 leased 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 plant, 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 must 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 certain pre-determined time periods (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

Page 22

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 valuesjudgment of our hedging instruments are determined based on third party forward price quotes for NYMEX Henry Hub and West Texas Intermediate closing prices.management.

Reserves.The estimates of oil and gas reserves are probably 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 projecting the timing of future development expenditures. In addition, reserve estimates of new discoveries are more impreciseless precise than those of producing properties withdue 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.

ResultsThere are several factors which could change our estimates of Operationsoil 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 inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144 when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates. We have recognized non-cash pretax charges of $0.4 million, $0.8

23

million and $33.6 million for 2003, 2002 and 2001, respectively, related to the impairment of oil and gas properties.

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.

Selected Financial Data – ConsolidatedCoal 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.