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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, 2002

Commission File Number 0-753

PENN VIRGINIA CORPORATION

One Radnor Corporate Center, Suite 200

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.  ¨

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.

As of February 27, 2003, 8,947,418 shares of common stock of the registrant were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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Penn Virginia Corporation and Subsidiaries

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Part 1

ITEM 1 – BUSINESS

General

Penn Virginia Corporation (“Penn Virginia” or the “Company”) is a Virginia corporation founded in 1882. We are engaged in the exploration, development and production of oil and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States. We also collect royalties on various oil and gas properties in which we own a mineral fee interest. At December 31, 2002, we had proved reserves of approximately 5.4 million barrels of oil and condensate and 241 billion cubic feet (Bcf) of natural gas, or 273 billion cubic feet equivalent (“Bcfe”).

Until October 30, 2001, we also engaged directly in the leasing and management of coal properties in the Central Appalachian region of the United States. In September 2001, we transferred our coal properties and related assets and liabilities to Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a newly formed Delaware limited partnership. On October 30, 2001, the Partnership completed its initial public offering (“IPO”) of approximately 7.5 million common units at $21.00 per unit, which are traded on the New York Stock Exchange under the symbol PVR. At December 31, 2002, the Partnership owned approximately 615 million tons of proven and probable coal reserves, including approximately 120 million tons of such reserves that were acquired in December 2002 related to a strategic alliance with Peabody Energy Corporation (“Peabody”). The Partnership’s coal reserves are located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. The Partnership does not operate any mines, but has leased its reserves under 51 leases to 28 different operators who mine coal at 61 mines in exchange for royalty payments to PVR. Lessees other than those which are affiliates of Peabody (the “Peabody Lessees”) are generally required to make royalty payments to the Partnership based on the amount of coal they produce from the Partnership’s properties and the price at which they sell the coal, subject to fixed minimum royalty rates per ton. The Peabody Lessees are required to make payments based on fixed royalty rates which escalate annually. In managing its properties, PVR actively works with its lessees to develop efficient methods to exploit reserves and to maximize production from properties. Additionally, the Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to generate coal service revenues. The Partnership also generates timber sales from timber owned. The Partnership owned approximately 168 million board feet (“MMbf”) of timber at December 31, 2002.

Our wholly owned subsidiary, Penn Virginia Resource GP, LLC, a Delaware limited liability company, serves as general partner of the Partnership. As of December 31, 2002, we owned approximately 45 percent of the Partnership, consisting of a two percent general partner interest, 42 percent subordinated units, and one percent common units. As part of our ownership of PVR’s general partner, we also own the rights, referred to as Incentive Distribution Rights, to receive an increasing percentage of quarterly distribution 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.

Financial Information

We operate in two primary business segments. We are in the oil and natural gas exploration and production business and, through our interests in PVR, we are in the coal royalty and land management business. For financial statement purposes, the assets, liabilities and earnings of PVR are included in our consolidated financial statements, with the public unitholders’ ownership interest reflected as a minority interest. See Note 19 (Segment Information) of the Notes to the Consolidated Financial Statements, for financial information concerning our business segments.

Oil and Gas Operations

General

Our oil and gas properties are located primarily in the eastern and Gulf Coast onshore areas of the United States. At December 31, 2002, we had 273 Bcfe of proved reserves (88 percent natural gas) including 226 Bcfe held through various working interests and 47 Bcfe held by royalty interests. During 2002, 349 thousand barrels of oil and condensate and 18.7 Bcf of natural gas, net to our interest, were produced from continuing operations compared with 164 thousand barrels and 13.1 Bcf in 2001. In addition, there were approximately 18 thousand barrels of oil and condensate and 16 million cubic feet (“MMcf”) of natural gas produced from properties which were sold in 2002 and reflected as discontinued operations. We received average prices of $23.63 and $22.94 per barrel and $3.35 and $4.06 per thousand cubic feet (“Mcf”) for crude oil and natural gas sales in 2002 and 2001, respectively. We also drilled 96

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gross (65.5 net) wells in 2002, of which 90 gross (60.9 net) were development and 6 gross (4.6 net) were exploratory. A total of 3 gross (1.6 net) exploratory wells were not successful.

Transportation

The majority of our natural gas production is transported to market primarily on three major transmission systems. Duke Energy, Inc., Nisource, Inc. and Dominion Energy, Inc. transported 39 percent, 24 percent and 20 percent, respectively, of our 2002 natural gas production. The remainder was divided among several pipeline companies in Texas, Louisiana and West Virginia. In almost all cases, our natural gas is sold at the interconnects with the transmission pipelines. For additional information, see Item 1 – Risks Associated with Business Activities – Oil and Gas – Transportation.

Marketing and Hedging

We generally sell our natural gas using the spot market and short-term fixed price physical contracts. From time to time, we enter into commodity derivative contracts or fixed price physical contracts to mitigate the risk associated with the volatility of natural gas prices. Recently, we have utilized swaps and costless collars in connection with our hedging activities. Gains and losses from hedging activities are included in revenues when the hedged production is sold. We recognized a loss of $1.0 million on settled hedging activities in 2002, a gain of $1.9 million in 2001, and no gain or loss in 2000. In 2002, we hedged approximately 44 percent of our natural gas base production at an average NYMEX Henry Hub floor price of $2.98 per MMbtu and a ceiling price of $3.53 per MMbtu. For crude oil, we hedged approximately 76 percent of our 2002 crude oil production at an average floor price or $21.31 per barrel and a ceiling price of $25.72 per barrel. See Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Quantitative and Qualitative Disclosures about Market Risk, for information about our price risk management positions for 2003, 2004 and the first quarter of 2005.

Coalbed Methane Drilling Venture

In August 2002, we entered into an agreement with CDX Gas, LLC (“CDX”), a private owner of proprietary horizontal drilling technology, to explore for and develop coalbed methane (“CBM”) in 16,000 square miles of property located in Central Appalachia as well as in the Devonian Shale formation. Our agreement with CDX is generally for five years and provides that we and CDX will have a 60 percent and 40 percent working interest, respectively, in future CBM projects conducted on property owned by us and subject to the agreement. On future projects conducted on property not owned by us, we and CDX will generally each have a 50 percent working interest.

Coal Royalty and Land Management Operations

Overview

At December 31, 2002, the Partnership owned and leased approximately 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky containing approximately 615 million tons of coal reserves. The Partnership earns coal royalty revenue, based on long-term lease agreements, from 28 coal-mining operators actively mining under 51 separate leases at 61 mines. Coal royalty revenues under non-Peabody leases are based on the higher of a percentage of the gross sales price or a fixed price per ton of coal, with pre-established minimum monthly or annual payments. Under the Peabody leases, coal royalty revenues are based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. The Partnership does not operate coal mines. The Partnership provides fee-based coal preparation and transportation facilities to some of its lessees to enhance their production levels and generate additional coal service revenues.

The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. The Partnership owned approximately 168 million board feet of standing saw timber at December 31, 2002. The Partnership’s timber inventory only includes timber that can be harvested and is greater than 12 inches in diameter.

In December 2002, the Partnership announced the formation of an important strategic alliance with Peabody Energy Corporation, the largest private sector coal company in the world. Central to the transaction was the purchase from and leaseback to Peabody of approximately 120 million tons of coal reserves located in New Mexico (80 million tons) and northern West Virginia (40 million tons) (the “Peabody Acquisition”). As a result of the Peabody Acquisition, the Partnership’s total reserves increased by approximately 25 percent to 615 million tons. The Peabody Acquisition was funded with $72.5 million in cash and the issuance by the Partnership to

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Peabody of 1,522,325 common units and 1,240,833 Class B common units. Of the Class B common units issued, 293,700 are currently being held in escrow pending certain approvals from the State of New Mexico and Peabody’s acquisition and transfer to PVR of certain reserves. As a result of the escrow arrangement, 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 year ended December 31, 2002.

The alliance with Peabody accomplishes several strategically important goals. It provides geographic diversity by exposing the Partnership to new markets in the western United States and northern Appalachia. The inclusion of affiliates of Peabody as a significant part of the Partnership’s lessee mix adds additional strength and stability to its lessee group. Peabody is incentivized to source additional assets to the Partnership in the future. This incentive is derived not only from Peabody’s ownership of approximately 15 percent of the Partnership’s common units, but also from its right to share in the general partner’s incentive distribution rights if Peabody sells additional coal assets to the Partnership in the future. See Item 1 – Corporate and Other – Partnership Distributions, Incentive Distribution Rights for more information.

In addition to the Peabody Acquisition, in August 2002, the Partnership purchased approximately 16 million tons of coal reserves in northern Appalachia for $12 million. This acquisition was the Partnership’s first outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominately high sulfur, high BTU coal reserves.

In June 2001, the Partnership acquired the Fork Creek property in West Virginia, purchasing approximately 53 million tons of coal reserves for $33.1 million. In early 2002, the operator at Fork Creek filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code and operations at the mine were idled on March 4, 2002. The operator continued to pay minimum royalties until the Partnership recovered its lease on August 31, 2002. In November 2002, the Partnership purchased various infrastructure at Fork Creek for $5.1 million plus the assumption of certain reclamation liabilities and stream mitigation obligations. With control of the reserves, permits and the critical infrastructure, PVR’s management is working diligently to put a new, financially stable operator in place at Fork Creek. As is customary in the Partnership’s operations, PVR intends to assign all related reclamation liabilities to the new operator.

Coal Royalties

The Partnership’s lessees mined approximately 14.3 million tons of coal in 2002 from PVR’s properties and paid an average royalty of $2.20 per ton, compared with approximately 15.3 million tons mined in 2001 at an average royalty of $2.11 per ton.

Timber Sales

Timber is harvested in advance of lessee mining to prevent loss of the resource. Timber is sold as individual parcels in competitive bid sales or on a contract basis, where PVR pays independent contractors to harvest timber while PVR directly markets the product. The Partnership sold approximately 8.3 MMbf in 2002 at an average price of $187 per thousand board feet (“Mbf”), compared with 8.7 MMbf at an average price of $168 per Mbf in 2001.

Coal Services

The Partnership generates coal service revenues from fees charged to lessees for the use of the Partnership’s coal preparation and transportation facilities. The majority of these fees have been generated by the Partnership’s unit train loadout facility, which was completed in April 1999 at a cost of $5.2 million. This facility accommodates 108-car unit trains, which can be loaded in approximately four hours. Lessees utilize the unit train loadout facility to reduce delivery costs incurred by their customers. The Partnership recognized $1.7 million in coal service revenues in 2002 and 2001. Such amounts are reported in other revenues in the Consolidated Statements of Income included herein.

Corporate and Other

Partnership Distributions

We are entitled, through our wholly owned subsidiaries, to receive certain cash distributions payable with respect to the subordinated and common units of PVR held by such subsidiaries as well as certain cash distributions payable with respect to general partner incentive distribution rights held by our general partner subsidiary.

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Cash Distributions. The Partnership made its first cash distribution of $0.34 per common and subordinated unit in February 2002 for the period October 30, 2001 through December 31, 2001. For 2002, the Partnership made quarterly cash distributions of $0.50 per common unit and subordinated unit. The Partnership intends to increase quarterly cash distributions to $0.52 per common unit and subordinated unit beginning with the distribution payable in May 2003 with respect to the first quarter of 2003.

Incentive Distribution Rights. Our wholly owned subsidiary is the general partner of PVR and, as such, holds certain incentive distribution rights which represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the Partnership has paid minimum quarterly distributions and certain target distribution levels have been achieved. The minimum quarterly distribution is $0.50 per unit ($2.00 per unit on an annual basis). The incentive distributions rights are payable as follows:

If for any quarter:

then, PVR will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner subsidiary in the following manner:

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution on the common units. In conjunction with the Peabody Acquisition, our general partner subsidiary has issued a special membership interest which entitles Peabody to receive increased percentages, starting at zero and increasing up to 40 percent, of payments PVR makes to our general partner subsidiary with respect to incentive distribution rights if PVR purchases additional assets from Peabody in the future.

Investments

During 2001, we sold 3,307,200 shares of Norfolk Southern Corporation (NYSE: NSC) common stock. The shares were sold in open market transactions on the New York Stock Exchange at an average price of $17.39 per share. Our 3,307,200 common shares of Norfolk Southern Corporation generated dividends of $0.2 million in 2001 and $2.6 million in 2000. We received a quarterly dividend of $0.06 per share in 2001, which was a reduction from the $0.20 per share realized in 2000. We had no available-for-sale securities at December 31, 2002 and 2001. See Note 5 (Investments and Dividend Income) of the Notes to the Consolidated Financial Statements for additional information.

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Risks Associated with Business Activities

Oil and Gas

Competition

The oil and natural gas industry is very competitive. Competition is particularly intense in the acquisition of prospective oil and natural gas properties and oil and gas reserves. Our competitive position depends on our geological, geophysical and engineering expertise, our financial resources, our ability to develop properties and our ability to select, acquire and develop proved reserves. We compete with a substantial number of other companies having larger technical staffs and greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. We compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time.

Price Volatility

Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets that are generally outside of our control. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas and/or crude oil could have a material adverse effect on the Company’s financial position and results of operations (including reduced cash flow and borrowing capacity), the quantities of natural gas and crude oil reserves that we can economically produce, the quantity of estimated proved reserves that may be attributed to our properties and our ability to fund our capital program.

Drilling and Operating Risks

Our drilling operations are subject to various risks common in the industry, including cratering, explosions, fires and uncontrollable flows of oil, gas or well fluids. Our drilling operations are also subject to the risk that no commercially productive natural gas or oil reserves will be encountered. The cost of drilling, completing and operating wells is often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including drilling conditions, pressure or irregularities in formations, equipment failures or accidents and adverse weather conditions.

Transportation

We transport our natural gas to market on various gathering and transmission pipeline systems owned by third parties. Gathering fees are primarily paid by the purchaser of the natural gas. The majority of natural gas sales contracts are one year or less in duration and contain relevant monthly index pricing provisions. Interruptible gathering rates have increased over the years as pipelines have implemented the mandatory unbundling of gathering services (Federal Energy Regulatory Commission Order 636) from other transportation services. In 2002, Duke Energy, Inc. gathered and transported approximately 39 percent of our natural gas, Nisource, Inc. (formerly Columbia Gas Transmission) approximately 24 percent, and Dominion Energy, Inc. approximately 20 percent, with the remainder divided among several pipeline companies in Texas, West Virginia and Louisiana. Production could be adversely affected by shutdowns of the pipelines for maintenance or replacement as transportation options are limited.

Regulation

State Regulatory Matters. Various aspects of our oil and natural gas operations are regulated by administrative agencies under statutory provisions of the states where such operations are conducted. All of the jurisdictions in which we own or operate producing crude oil and natural gas properties have statutory provisions regulating the exploration for and production of crude oil and natural gas. These provisions include the permitting for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, provisions relating to the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, and the plugging and abandoning of wells. Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the number of wells that may be

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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.

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 natural gas, 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’ sales 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. 637, which, among other things, (i) permits pipelines to charge different maximum cost-based rates for peak and off-peak times, (ii) encourages auctions for pipeline capacity, (iii) requires pipelines to implement imbalance management services, and (iv) restricts the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders. In addition, the FERC has implemented regulations governing 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 new pipeline facilities to charge rates based solely on the 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.

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Coal Royalty and Land Management

Although the Partnership intends to make quarterly cash distributions of $0.52 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 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 would 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.

In addition, the utility industry, which is the most significant end-user of coal, is subject to extensive regulation regarding the environmental impact of its power generation activities which could affect demand for 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.

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Regulation

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 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 effect 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-products of coal combustion, but consideration is now being given to regulating certain hazardous air pollutant components that are found in coal combustion exhaust, including mercury. 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.

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 steams 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.

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 dies from this disease.

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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 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 lessees over the next five years. The Partnership’s lessees are in the planning phase for obtaining permits for the remaining reserves planned to be mined over the next five years. However, they cannot make 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 104 employees at December 31, 2002, including 30 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 annual report on Form 10-K, quarterly reports on Form 10-Q 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.

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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.

A. James 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 – 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 – 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.

Nancy M. 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. 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’ 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 – 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.

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

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ITEM 2 – PROPERTIES

Facilities

We are headquartered in Radnor, Pennsylvania with additional offices in Kingsport, Tennessee, Houston, Texas and Charleston, West Virginia. 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 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 affect the value of such properties.

Of the 615 million tons of proven and probable coal reserves to which the Partnership has rights as of December 31, 2002, PVR owned the mineral rights and the majority of related surface rights to 572 million tons, or 93 percent, and leased the remaining 43 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.

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Oil and Gas

Production and Pricing

The following table sets forth production, sales prices and production costs with respect to our properties for the years ended December 31, 2002, 2001 and 2000.

*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.

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Proved Reserves

We had proved reserves of 241 Bcf of natural gas and 5.4 million barrels of crude oil and condensate at December 31, 2002. The present value 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) proved undeveloped drilling locations.

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 $355 million, $189 million and $467 million at December 31, 2002, 2001 and 2000, respectively. For information on the changes in standardized measure of discounted future net cash flows. See Note 22 (Supplementary Information on Oil and Gas Producing Activities (Unaudited)) of the Notes to the Consolidated Financial Statements, for more information.

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. 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 substantial fluctuations as a result of numerous other factors. See Item 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 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, the pre-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

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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. The acreage is located in the eastern and southern portions 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.

Productive Wells

The number of productive oil and gas wells in which we had a working interest at December 31, 2002 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.

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Coal Royalty and Land Management

The Partnership’s coal reserves at December 31, 2002 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 proven and probable coal reserves are estimated at 615 million tons as of December 31, 2002. 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/or 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, 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 steam or metallurgical markets.

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.

The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. At December 31, 2002, the Partnership owned an estimated 168 MMbf of standing saw timber.

ITEM 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 HOLDERS

There were no matters submitted to a vote of security holders during the fourth quarter of 2002.

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PART II

ITEM 5 – MARKET FOR THE COMPANY’S COMMON STOCK AND RELATED STOCKHOLDER MATTERS

Common Stock Market Prices And Dividends

High and low closing stock 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.

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ITEM 6 – SELECTED FINANCIAL DATA

Five Year Selected Financial Data

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ITEM 7 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following review of operations and financial condition 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 and produces crude oil, condensate and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States. Our coal royalty and land management segment operates through our ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a Delaware limited partnership, see Note 2 (Penn Virginia Resource Partners, L.P.) of the Notes to the Consolidated Financial Statements.

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 intend to execute a program combining relatively low risk, moderate return development drilling in the east with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions. In addition to our continuing development program, we are expanding our eastern presence by developing coalbed methane gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to increase production rates from coalbed methane reserves we own. We are also committed to expanding our onshore Gulf Coast reserves and production internally through our drilling program and by acquiring reserves with favorable return potential.

In 2002, these efforts resulted in a 47 percent increase in oil 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 region for $32.5 million, which will provide a significant part of the expected growth in 2003 production.

Our oil and gas capital expenditures for 2003, including the January 2003 South Texas acquisition, are expected to be $110 to $120 million. Borrowings against our $140 million credit facility were $16 million as of December 31, 2002, and we expect to fund our 2003 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 in 2003 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. As of December 31, 2002, PVR had borrowed $90.9 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. Cash flow from operations, supplemented with credit facility borrowings, are expected to be adequate for PVR to fund 2003 capital expenditures and distributions to unitholders.

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.

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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 cost of the property has been impaired. As unproved leaseholds are determined to be productive, 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 oil and gas properties on our consolidated balance sheet. We expect to complete an evaluation of our unproved leaseholds over 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 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.

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

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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 projecting 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 at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing equipment and operating methods.

Results of Operations

Selected Financial Data – Consolidated

Consolidated Net Income

Our 2002 net income was $12.1 million, compared with $34.3 million in 2001 and $39.3 million in 2000. Revenues for 2002 were $111.0 million, compared with $96.6 million and $106.0 million in 2001 and 2000, respectively.

The 2001 results included a pre-tax gain on the sale of securities of approximately $54.7 million ($35.5 million after tax). Also included in the 2001 results was the impairment of certain oil and gas properties, for which we recorded a $33.6 million ($21.8 million after tax) impairment charge. In addition to the gain on sale of securities, net of the impairment charge noted above, the decrease in 2002 net income from 2001 was primarily due to lower natural gas prices and the minority interest resulting from the ownership change of our coal reserves in connection with the initial public offering of the Partnership’s common units in the fourth quarter of 2001.

In 2000, we recorded a pre-tax gain of $23.9 million ($15.5 million after tax) on the sale of non-strategic natural gas properties located in Kentucky and West Virginia. The decrease in 2001 net income from 2000 was primarily due to increased exploration, operating and general and administrative expenses as a result of the acquisition of Gulf Coast properties in 2001.

Corporate and Other

Dividends. In April 2001, we sold 3.3 million shares of common stock of Norfolk Southern Corporation at an average selling price of $17.39 per share. Proceeds, net of commissions, totaled approximately $57.4 million. As a result, dividend income decreased from $2.6 million in 2000 to $0.2 million in 2001. No dividends were received during 2002.

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Oil and Gas Segment

In our oil and gas segment, we explore for, develop and produce crude oil and natural gas in the eastern and Gulf Coast onshore regions of the United States.

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, the cost of the property has been impaired. As unproved leaseholds are determined to be productive, the related costs are transferred to proved leaseholds.

Oil and natural gas revenues are generally recorded using the entitlement method in which we recognize our ownership interest in the production as revenue. Each working interest owner in a well generally has the right to a specific percentage of production, although actual production sold may differ from an ownership percentage. Using entitlement accounting, a receivable is recorded when sales are less than our entitlement and deferred revenue is recognized when sales are greater than our entitlement.

We review our long-lived assets, including proved oil and natural gas properties, for possible impairment 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 using the expected present value of future net cash flows from proved reserves, utilizing a risk-free interest rate.

Our revenues, profitability and future rate of growth are highly dependent on the prevailing prices for oil and natural gas, which are affected by numerous factors that are generally beyond the Company’s control. Crude oil prices are generally determined by global supply and demand. Natural gas prices are influenced by national and regional supply and demand. A substantial or extended decline in the prices of oil or natural gas could have a material adverse effect on our revenues, profitability and cash flow and could, under certain circumstances, result in an impairment of our oil and natural gas properties.

Our future profitability and growth is also highly dependent on the results of our exploratory and development drilling programs.

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Selected Financial and Operating Data – Oil and Gas

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

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Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Revenues. Oil and gas revenues increased $13.7 million to $71.5 million in 2002 from 2001 primarily due to an increase in crude oil and natural gas production.

Crude oil and natural gas production increased to 20.8 Bcfe in 2002, a 47 percent increase over 2001. The increase was primarily due to the inclusion of a full year of production from the Gulf Coast oil and gas properties acquired in July 2001 and development drilling success in connection with our Gulf Coast, Mississippi and Appalachian assets. Approximately 90 percent of our 2002 production was natural gas.

The average natural gas price received during 2002 was $3.35 per Mcf compared with $4.06 per Mcf in 2001, a 17 percent decrease. The average oil price received was $23.63 per barrel for 2002, up three percent from $22.94 per barrel in 2001.

Due to the volatility of crude oil and natural gas prices, we sometimes hedge the price received for sales volumes through the use of swaps and costless collars. Gains and losses from hedging activities are included in revenues when the hedged production occurs. We recognized a loss on settled hedging activities of $1.0 million in 2002 and a gain of $1.9 million in 2001.

Operating expenses. Production costs increased from $5.6 million in 2001 to $9.3 million in 2002. The increase was primarily attributable to the full year impact of operating costs related to our acquisition of certain Gulf Coast oil and gas properties in late July of 2001.

Exploration expenses decreased from $11.5 million in 2001 to $7.5 million in 2002 due to lower exploratory dry hole costs incurred this year. Seismic expenditures were $4.7 million in 2002, up from $2.2 million in 2001. The impact of these higher costs was offset by reduced write-offs of unproved property in 2002.

Taxes other than income taxes increased by $1.2 million to $5.6 million in 2002. The increased taxes were a result of the higher production and revenue levels in 2002.

General and administrative (“G&A”) expenses increased to $8.4 million in 2002 from $5.3 million in 2001. The increase was primarily attributable to our acquisition of the Gulf Coast oil and gas properties in July 2001 and related personnel expenses.

Oil and gas depreciation, depletion and amortization (“DD&A”) increased to $26.3 million in 2002 from $16.4 million in 2001. This increase was primarily due to increased production related to the Gulf Coast assets acquired in July 2001, as well as increased DD&A rates due to changes in reserve estimates and capital additions.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Revenues. Oil and gas revenues increased $10.2 million to $57.0 million in 2001 from 2000 primarily due to an increase in crude oil and natural gas production.

Crude oil and natural gas sales combined increased 22 percent to $57.0 million due to a 19 percent increase in production. The increase was primarily due to production related to our acquisition of certain Gulf Coast oil and gas properties in July 2001 and to increased production from the Gwinville Field, offset in part by production lost from properties disposed of in the fourth quarter of 2000. Approximately 93 percent of our 2001 production was natural gas. The average natural gas price received during 2001 was $4.06 per Mcf compared with $3.95 per Mcf in 2000, a three percent increase. The average oil price received was $22.94 per barrel for 2001, down 15 percent from $26.84 per barrel in 2000. We recognized a gain of $1.9 million in 2001 on hedging activities with no gain or loss recognized in 2000.

Operating expenses. Production costs, consisting of lease operating expense and taxes other than income, increased from $7.4 million in 2000 to $10.0 million in 2001. Production costs increased from $0.62 per Mcfe in 2000 to $0.71 per Mcfe in 2001. The increase was primarily attributable to the acquisition of certain Gulf Coast oil and gas properties in July 2001.

Exploration expenses increased from $5.1 million in 2000 to $11.5 million in 2001. The $11.5 million in 2001 consisted of $2.4 million in seismic expenditures, charges relating to five gross (3.5 net) nonproductive exploratory wells and the impairment of unproved leasehold costs. Our increased seismic expenditures for the year, compared with 1.7 million in 2000, represented a continued effort to establish a balanced exploratory program.

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G&A expenses increased to $5.3 million in 2001 from $2.7 million in 2000. The increase was attributable to the acquisition of certain Gulf Coast oil and gas properties in late July of 2001 and related personnel expenses.

Oil and gas DD&A increased to $16.4 million in 2000 from $9.9 million in 2000. This increase was primarily due to increased production and a higher cost basis in the producing assets. The acquisition of certain Gulf Coast oil and gas properties in July 2001 was completed when crude oil and natural gas future prices were higher than forecasted prices at year-end 2001. As a result of low commodity prices in the fourth quarter 2001, we subjected all properties to impairment testing and recognized a pretax impairment charge related primarily to our Texas properties of $33.6 million ($21.8 million after tax).

Coal Royalty and Land Management Segment

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

The Partnership enters into leases with various third-party operators for the right to mine coal reserves on the Partnership’s properties in exchange for royalty payments. Coal royalty revenues under non-Peabody leases are based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. Under the Peabody leases, coal royalty revenues are based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. In addition to coal royalty revenues, the Partnership generates coal service revenues from fees charged to lessees for the use of coal preparation and transportation facilities. The Partnership also generates revenues from the sale of timber on its properties.

The coal royalty stream is impacted by several factors, which PVR generally cannot control. The number of tons mined annually is determined by an operator’s mining efficiency, labor availability, geologic conditions, access to capital, ability to market coal and ability to arrange reliable transportation to the end-user. The possibility exists that new legislation or regulations may be adopted which may have a significant impact on the mining operations of the Partnership’s lessees or their customers’ ability to use coal and may require PVR, its lessees or its lessee’s customers to change operations significantly or incur substantial costs.

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Selected Financial and Operating Data – Coal Royalty and Land Management

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Revenues. Coal royalty and land management segment revenues for the year ended December 31, 2002 were $38.6 million compared to $37.5 million for the year ended December 31, 2001, an increase of $1.1 million, or three percent.

Coal royalty revenues for the year ended December 31, 2002 were $31.4 million compared to $32.4 million for the year ended December 31, 2001, a decrease of $1.0 million, or three percent. Over these same periods, production decreased by 1.0 million tons, or seven percent, from 15.3 million tons to 14.3 millions tons. These decreases were primarily due to weaker coal demand in 2002 in general, and more specifically, the idling of production at the Fork Creek property caused by the lessee’s bankruptcy.

Timber revenues decreased to $1.6 million for the year ended December 31, 2002 from $1.7 million for the year ended December 31, 2001, a decrease of $0.1 million, or five percent. Volume sold declined 396 thousand board feet (Mbf), or five percent, to 8,345 Mbf in 2002, compared to 8,741 Mbf for 2001.

Coal services revenues remained constant at $1.7 million for the years ended December 31, 2002 and 2001. Slight increases in revenues generated from PVR’s modular preparation plants and dock loadout facility were offset by a minor reduction in revenues from its unit-train loadout facility.

Other revenues were $3.9 million for the year ended December 31, 2002 compared to $1.8 million for the year ended December 31, 2001, an increase of $2.1 million, or 122 percent. The increase was primarily due to the recognition of minimum rental payments received from the Partnership’s lessees which are no longer recoupable by the lessee. Two of PVR’s lessees, Horizon Resources, Inc. (formerly AEI Resources, Inc.) and Pen Holdings, Inc., both of which filed Chapter 11 bankruptcies during 2002, accounted for $1.9 million of minimum rental income in 2002.

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Operating expenses. Operating expenses, which include both lease operating expenses and taxes other than income, were $3.8 million for the years ended December 31, 2002 and 2001. Lease operating expenses were $2.9 million for the year ended December 31, 2002 compared to $3.2 million for the year ended December 31, 2001, a decrease of $0.3 million, or nine percent. This decrease is primarily due to a decrease in production by lessees on the Partnership’s subleased properties, offset by temporary mine maintenance costs on its Coal River property. Aggregate production from subleased properties decreased to 1.8 million tons for the year ended December 31, 2002 from 2.3 million tons for the year ended December 31, 2001. Taxes other than income for the year ended December 31, 2002 was $0.9 million compared to $0.6 million for the year ended December 31, 2001, an increase of $0.3 million, or 45 percent. The increase was primarily due to an increase in state franchise taxes resulting from the Partnership’s change from a corporate to a partnership structure in late 2001. Prior to the initial formation of the Partnership, franchise taxes were calculated based on filing as a corporation.

G&A expenses increased to $6.4 million for the year ended December 31, 2002 compared to $5.5 million for the year ended December 31, 2001, representing an 18 percent increase. The increase was primarily attributable to a full year of fees and expenses associated with the Partnership being a publicly traded entity.

Depreciation and depletion expense for the year ended December 31, 2002 was $4.0 million compared to $3.1 million for the year ended December 31, 2001, an increase of $0.9 million, or 28 percent. The increase in depreciation, depletion and amortization resulted from an increase in the depletive write-off rate per ton caused by a downward revision of coal reserves in the late 2001, higher cost coal properties being added to the depletable base as a result of recent acquisitions, and additional depreciation related to coal services capital projects.

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Revenues. Coal royalty and land management segment revenues were $37.5 million in 2001 and $30.2 million in 2000, representing a 24 percent increase.

Coal royalty revenues increased $8.1 million from $24.3 million in 2000 to $32.4 million in 2001. Production increases were the primary factor related to the increase in revenues. Royalty tons increased 2.8 million from 12.5 million in 2000 to 15.3 million in 2001, or 22 percent. These production increases were attributable to the start up of five new mines, the June 2001 acquisition of new properties and the completion of a capital project on another lease.

Timber revenues decreased to $1.7 million for the year ended December 31, 2001 from $2.4 million for the year ended December 31, 2000, a decrease of $0.7 million, or 27 percent. The decrease is primarily attributable to a decrease in the average price received for the timber from $257 per Mbf for the year ended December 31, 2000 to $168 per Mbf for the year ended December 31, 2001. The decrease reflects overall market conditions as well as the sale of lower priced species and lower quality timber.

Coal services revenues increased to $1.7 million for the year ended December 31, 2001 from $1.4 million in 2000, an increase of $0.3 million, or 20 percent. The increase is a direct result of the addition of a small preparation plant put into service during 2001 and additional usage of the Partnership’s existing coal service facilities.

Other revenues were $1.8 million for the year ended December 31, 2001 compared with $2.1 million for the year ended December 31, 2000, a decrease of $0.3 million, or 17 percent. The decrease was primarily due to gains from the sale of property and equipment in 2000, offset by the recognition of minimum rental payments received from lessees which are no longer recoupable.

Operating expenses. Operating expenses were $3.8 million for the year ended December 31, 2001 compared with $3.5 million for the year ended December 31, 2000, an increase of $0.3 million, or 10 percent. This variance is primarily due to an increase in production by lessees on PVR’s subleased properties resulting in royalty expense incurred. Production from subleased properties increased from 2.1 million tons for the year ended December 31, 2000 to 2.3 million tons for the year ended December 31, 2001, an increase of 0.2 million tons, or 10 percent.

G&A expenses increased to $5.5 million for the year ended December 31, 2001 compared to $4.8 million for the year ended December 31, 2000. This increase is primarily attributable to fees associated with tax preparation and public reporting by the Partnership.

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Depreciation and depletion expense for the year ended December 31, 2001 was $3.1 million compared with $2.0 million for the year ended December 31, 2000, an increase of $1.1 million, or 51 percent. This increase primarily resulted from coal production increases of 22 percent. Depreciation and depletion expense increased, on a per ton basis, to $0.20 per ton for the year ended December 31, 2001 from $0.16 for the year ended December 31, 2000. The $0.04 increase on a per ton basis results from increased production from the Coal River property, which has a significantly higher cost basis.

Reserves

Oil and Gas Reserves

Our total proved reserves at December 31, 2002 were 273.4 Bcfe, compared with 252.8 Bcfe at December 31, 2001. At December 31, 2002, proved developed reserves comprised 79 percent of our total proved reserves, compared with 78 percent at December 31, 2001. We have 128 net proved undeveloped drilling locations at December 31, 2002, compared with 93 locations at December 31, 2001.