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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, 2003

Commission File Number 0-753

PENN VIRGINIA CORPORATION

Three Radnor Corporate Center, Suite 230

100 Matsonford Road

Radnor, PA 19087

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

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

None

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

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

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

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

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

As of March 4, 2004, 9,114,277 shares of common stock of the registrant were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

PENN VIRGINIA CORPORATION AND SUBSIDIARIES

PART I

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 crude 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, 2003, we had proved reserves of approximately 6.6 million barrels of oil and condensate and 283 billion cubic feet (“Bcf”) of natural gas, or 323 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, 2003, the Partnership owned approximately 588 million tons of proven and probable coal reserves 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 53 leases to 29 different operators who mine coal at 54 mines in exchange for royalty payments to PVR. 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 revenues from the sale of standing timber on its properties. The Partnership owned approximately 166 million board feet (“MMbf”) of timber at December 31, 2003.

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, 2003, we owned approximately 45 percent of the Partnership, consisting of a two percent general partner interest and 43 percent limited partner interest. 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 the Partnership’s quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. See Item 1—Business—Corporate and Other for more information on incentive distribution rights.

Financial Information

We operate in two primary business segments. We are in the crude 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 20. 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 onshore Gulf Coast areas of the United States. At December 31, 2003, we had 323 Bcfe of proved reserves, of which 88 percent was natural gas. Seventy-eight percent or those proved reserves were proved developed reserves. During 2003, 625 thousand barrels of oil and condensate and 20.1 Bcf of natural gas, net to our interest, were produced from continuing operations compared with 349 thousand barrels and 18.7 Bcf in 2002. We received average prices of $26.91 and

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$23.63 per barrel for crude oil and $5.31 and $3.35 per thousand cubic feet (“Mcf”) for natural gas in 2003 and 2002, respectively. We also drilled 180 gross (132.1 net) wells in 2003, of which 162 gross (118.0 net) wells were development and 18 gross (14.1 net) wells were exploratory. A total of 3 gross (2.9 net) exploratory wells were not successful and 10 gross (10 net) exploratory wells were under evaluation at December 31, 2003.

Transportation

The majority of our natural gas production is transported to market on five major pipeline or transmission systems. NiSource Inc., Dominion Transmission, Inc., Duke Energy Corporation, Exxon Mobil Corporation and Crosstex Energy Services LTD transported 21 percent, 20 percent, 19 percent, 12 percent and 8 percent, respectively, of our 2003 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 interconnects with 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 spot market and short-term fixed price physical contracts. For the year ended December 31, 2003, three customers of the oil and gas segment, Dominion Transmission, Inc., El Paso Corporation and Duke Energy Corporation accounted for approximately 19 percent, 13 percent and 12 percent, respectively, of our total revenues. 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 $6.1 million on settled hedging activities in 2003, a loss of $1.1 million in 2002 and a gain of $1.9 million in 2001. In 2003, we hedged approximately 45 percent of our natural gas production at an average NYMEX Henry Hub floor price of $3.64 per MMbtu and a ceiling price of $5.61 per MMbtu for costless collars, and an average $4.70 per MMbtu for swaps. For crude oil, we hedged approximately 26 percent of our 2003 crude oil production at an average floor price of $23.00 per barrel and a ceiling price of $28.75 per barrel for costless collars, and an average $26.82 per barrel for swaps. See Item 7A.— Quantitative and Qualitative Disclosures about Market Risk for information about our price risk management positions for 2004 and 2005.

Coal Royalty and Land Management Operations

General

At December 31, 2003, the Partnership properties contained approximately 588 million tons of proven and probable coal reserves located on 241,000 acres in Virginia, West Virginia, New Mexico and eastern Kentucky. The Partnership earns coal royalty revenues, based on long-term lease agreements, from 29 coal mining operators actively mining under 53 separate leases at 54 mines. Approximately 72 percent of PVR’s 2003 coal royalty revenues and 99 percent of its 2002 coal royalty revenues were based on the higher of a percentage of gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of PVR’s 2003 and 2002 coal royalty revenues was 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 166 million board feet of standing saw timber at December 31, 2003. The Partnership’s timber inventory only includes timber that can be harvested and is greater than 12 inches in diameter.

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In 2002, the Partnership made two reserve acquisitions as well as an infrastructure acquisition. In December 2002, the Partnership acquired from Peabody Energy Corporation (“Peabody”) approximately 120 million tons of proven and probable coal reserves located in New Mexico (80 million tons) and West Virginia (40 million tons) (the “Peabody Acquisition”). In addition to the Peabody Acquisition, in August 2002, the Partnership purchased approximately 16 million tons of proven and probable coal reserves located on the Upshur properties in northern Appalachia (the “Upshur Acquisition”). The Upshur Acquisition was PVR’s first investment outside of central Appalachia. In November 2002, the Partnership also purchased various infrastructure located on its West Coal River property (formerly know as Fork Creek) including a 900 ton per hour coal preparation plant, a unit train loadout facility and a railroad-granted rebate on coal loaded through the facility.

Coal Royalties

The Partnership’s lessees mined approximately 26.5 million tons of coal in 2003 from PVR’s properties and paid an average royalty of $1.90 per ton, compared with approximately 14.3 million tons mined in 2002 at an average royalty of $2.20 per ton.

Timber Sales

The Partnership harvests timber 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 5.3 MMbf in 2003, compared with 8.3 MMbf in 2002.

Coal Services

The Partnership generates coal service revenues from fees charged to lessees for 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 located on its Wise property, which was completed in April 1999 at a cost of $5.2 million. This facility accommodates up to 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 $2.1 million in coal service revenues in 2003, compared to $1.7 million in 2002. Such amounts are reported as other revenues in the Consolidated Statements of Income included herein.

Corporate and Other

Partnership Distributions

Cash Distributions. The Partnership paid cash distributions of $2.06 per common and subordinated unit during the year ended December 31, 2003. In 2004, the Partnership expects to make distributions of $2.08 or more per common and subordinated unit.

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 incentive distribution rights held by our general partner subsidiary. The Company received distributions from PVR of $16.8 million and $14.9 million in 2003 and 2002, respectively.

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:

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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, and if PVR purchases additional assets from Peabody in the future, 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.

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. We received a quarterly dividend of $0.06 per share in 2001. We had no available-for-sale securities at December 31, 2003 and 2002. See Note 5. Investments and Dividend Income of the Notes to the Consolidated Financial Statements for additional information.

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.

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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 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, high 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 2003, NiSource Inc. gathered and transported approximately 21 percent of our natural gas, Dominion Transmission, Inc. approximately 20 percent, Duke Energy Corporation approximately 19 percent, Exxon Mobil Corporation approximately 12 percent, and Crosstex Energy Services LTD approximately 8 percent, with the remainder divided among several pipeline companies in Texas, Louisiana and West Virginia. Production could be adversely affected by disruptions or curtailments of the operations of 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 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.

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

Commencing in April 1992, the FERC issued Order Nos. 636, 636-A, 636-B and 636-C (“Order No. 636”), which require interstate pipelines to provide transportation separate, or “unbundled,” from the pipelines’ sale 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, 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 Nos. 637, 637-A and 637-B which, among other things, (i) permit pipelines to charge different maximum cost-based rates for peak and off-peak periods, (ii) encourage auctions for pipeline capacity, (iii) require pipelines to implement imbalance management services, and (iv) restrict the ability of pipelines to impose penalties for imbalances, overruns, and non-compliance with operational flow orders. In addition, the FERC has regulations in place that govern the procedure for obtaining authorization to construct new pipeline facilities and has issued a policy statement, which it largely affirmed in a recent order on rehearing, establishing a presumption in favor of requiring owners of newly constructed pipeline facilities to charge rates based on the incremental costs associated with such new pipeline facilities.

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

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

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Coal Royalty and Land Management

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

Competition

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

Operating Risks

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

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

Certain Regulatory and Legal Matters.

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

In July 1997, the U.S. Environmental Protection Agency (“EPA”) adopted more stringent ambient air quality standards for particulate matter and ozone. Particulate matter includes small particles that are emitted during the combustion process. In a February 2001 decision, the U.S. Supreme Court largely upheld EPA’s position, although it remanded 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 affect 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, but in January 2004, EPA proposed regulations to control emissions of mercury, a hazardous air pollutant from power plants that combust coal, as well as nitrogen oxides and sulfur dioxide, which are also power plant pollutants, Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.

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

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

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Surface Mining Valley Fills. Over the course of the last several years, opponents of surface mining have filed three lawsuits challenging the legality of permits authorizing the construction of valley fills for the disposal of coal mining overburden under federal and state laws applicable to surface mining activities. Although two of these challenges were successful in the United States District Court for the southern District of West Virginia (the “District Court”), the United States Court of Appeals for the Fourth Circuit overturned both of those decisions in Bragg v. Robertson in 2001 and in Kentuckians For The Commonwealth v. Rivenburgh in 2003.

On October 23, 2003, a third lawsuit involving the disposal of coal mining overburden was filed under the name of Ohio Valley Environmental Coalition v. Bulen. In this case, which was also filed in the District Court, several public interest group plaintiffs have alleged that the Army Corps of Engineers violated the Clean Water Act (“CWA”) and other federal regulations when it issued Nationwide Permit 21, a general permit for the disposal of coal mining overburden into United States waters. This most recent suit also challenges certain individual discharge authorizations in West Virginia, including several involving the mining activities of the Partnership’s lessees. If the plaintiffs prevail in this latest lawsuit, lessees who have received authorization for discharges pursuant to Nationwide Permit 21 could be prevented from undertaking future discharges until they receive individual CWA permits, and future operations could require individual permits. Obtaining these individual permits is likely to substantially increase both the time and the costs of obtaining CWA permits for our lessees and other coal mining operators throughout the industry where any such unfavorable ruling may be applied. These increases could adversely affect our coal royalty revenues. Although the Partnership expects that any ruling for the plaintiffs would be appealed to the Fourth Circuit, the coal mining industry, including the operations of our lessees, could be significantly adversely impacted by the initial effects of an adverse decision while any appeal is pending.

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

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

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

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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 them over the next five years. The Partnership’s lessees are also in the planning phase for obtaining permits for the additional reserves planned to be mined over the following five years. However, they cannot give 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 116 employees at December 31, 2003, including 32 employees who directly provide services for PVR through its general partner. We consider our relations with our employees to be good.

Available Information

The Company’s Internet address is www.pennvirginia.com. We make available free of charge on or through our Internet website our Governance Principles, Code of Business Conduct and Ethics, Executive and Financial Officer Code of Ethics and the charters of each of our Audit Committee, Nominating and Governance Committee, Compensation and Benefits Committee and Oil and Gas Committee. We also make available free of charge on or through our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the Securities and Exchange Commission.

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.

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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.

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.

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

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

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

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

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

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

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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. All of our office facilities are leased. We believe that our properties are adequate for our current needs.

Title to Properties

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

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

Of the 588 million tons of proven and probable coal reserves to which the Partnership had rights as of December 31, 2003, PVR owned the mineral interests and the majority of related surface rights to 544 million tons, or 93 percent, and leased the remaining 44 million tons, or 7 percent, from unaffiliated third parties.

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Information Regarding Oil and Gas Properties

Production and Pricing

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

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Proved Reserves

The following table presents certain information regarding our proved reserves as of December 31, 2003, 2002 and 2001. The proved reserve estimates presented below were prepared by Wright and Company, Inc., independent petroleum engineers. For additional information regarding estimates of proved reserves, the preparation of such estimates by Wright and Company, Inc. and other information about our oil and gas reserves, see Note 23. Supplemental Information on Oil and Gas Producing Activities (Unaudited) of the Notes to the Consolidated Financial Statements. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies.

The standardized measure of discounted future net cash flows, which represents the present value of future net revenues after income taxes discounted at ten percent, was $512 million, $355 million and $189 million as of December 31, 2003, 2002 and 2001, respectively. For information on the changes in standardized measure of discounted future net cash flows, see Note 23. Supplemental Information on Oil and Gas Producing Activities (Unaudited) of the Notes to the Consolidated Financial Statements.

In accordance with the Securities and Exchange Commission’s guidelines, the engineers’ estimates of future net revenues from our properties and the pre-tax SEC PV10 value thereof are made using oil and natural gas sales prices in effect as of December 31, 2003. The prices are held constant throughout the life of the properties except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations. Prices for oil and gas are subject to substantial seasonal fluctuations as well as fluctuations resulting from 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

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that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. Therefore, neither the pre-tax nor after-tax SEC PV10 value amounts shown above should 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 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, 2003. The acreage is located in the eastern and Gulf Coast areas of the United States.

Wells Drilled

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

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

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Productive Wells

The number of productive oil and gas wells in which we had a working interest at December 31, 2003 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.

Information Regarding Coal Royalty and Land Management Properties

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

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

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

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

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

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

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

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

The Partnership’s timber assets consist of various hardwoods, primarily red oak, white oak, yellow poplar and black cherry. At December 31, 2003, the Partnership owned an estimated 166 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 2003.

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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 sales 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.

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

Overview

Penn Virginia Corporation (“Penn Virginia” or the “Company”) is an independent energy company that is engaged in two primary business segments. Our oil and gas segment explores for, develops, produces and sells crude oil, condensate and natural gas primarily in the eastern and Gulf Coast onshore areas of the United States. Our coal royalty and land management segment operates through our 44.5 percent ownership in Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”). Penn Virginia and PVR are both publicly traded on the New York Stock Exchange under the symbols PVA and PVR, respectively. Due to our control of the general partner of PVR, the financial results of the Partnership are included in our consolidated financial statements. However, PVR functions with a capital structure that is independent of the Company, consisting of its own debt instruments and publicly traded common units. The following diagram depicts our ownership of PVR:

As a result of our ownership in the Partnership, we receive cash payments from PVR in the form of quarterly cash distributions. We received approximately $16.8 million of cash distributions from PVR during 2003. As part of our ownership of PVR’s general partner, we also own the rights, referred to as incentive distribution rights, to receive an increasing percentage of quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. See Item 1—Business—Corporate and Other for more information on incentive distribution rights. As of December 31, 2003, PVR had not achieved a level of distribution to allow us to receive an increased percentage of available cash.

We are committed to increasing value to our shareholders by conducting a balanced program of investment in our two business segments. In the oil and gas segment, we expect to execute a program combining relatively low risk, moderate return development drilling in the Appalachian region of Virginia and West Virginia with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions. In addition to our continuing conventional development program, we are

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

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

Our oil and gas capital expenditures for 2004 are expected to be approximately $100 million. Borrowings against our credit facility were $64 million out of $150 million available as of December 31, 2003, and we expect to fund our 2004 capital expenditures with a combination of internal cash flow and credit facility borrowings.

Coal-related capital expenditures on existing properties in 2004 are expected to be less than $0.5 million. As of December 31, 2003, PVR had borrowed $91.8 million against its debt facilities. Cash flow from operations, supplemented with credit facility borrowings, is expected to be adequate for PVR to fund 2004 capital expenditures and distributions to unitholders.

2003 Performance—Oil and Gas Segment

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Critical Accounting Policies and Estimates

The process of preparing financial statements in accordance with Generally Accepted Accounting Principals (“GAAP”) requires the management of the Company to make estimates and judgments regarding certain items and transactions. It is possible that materially different amounts could be recorded if these estimates and judgments change or if the actual results differ from these estimates and judgments. We consider the following to be the most critical accounting policies which involve the judgment of our management.

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

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

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

There are several factors which could change our estimates of oil and gas reserves. Significantly higher or lower product prices could lead to changes in the amount of reserves due to economic limits. An additional factor that could result in a change of recorded reserves is the reservoir decline rates being different than those assumed when the reserves were initially recorded. Estimation of future production and development costs is also subject to change partially due to factors beyond our control, such as energy costs and inflation or deflation of oil field service costs. Additionally, we perform impairment tests pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 144 when significant events occur, such as a market move to a lower price environment or a material revision to our reserve estimates. We have recognized non-cash pretax charges of $0.4 million, $0.8

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

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

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

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

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

A portion of the carrying value of the Company’s oil and gas properties is attributable to unproved properties. At December 31, 2003, the costs attributable to unproved properties were approximately $60 million. These costs are not currently being depreciated or depleted. As exploration work progresses and the reserves on these properties are proven, capitalized costs of the properties will be subject to depreciation and depletion. If the exploration work is unsuccessful, the capitalized costs of the properties related to the unsuccessful work will be expensed. The timing of any writedowns of these unproven properties, if warranted, depends upon the nature, timing and extent of future exploration and development activities and their results.

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

Acquisitions

Oil and gas

On January 22, 2003, we acquired a 25 percent non-operating working interest in properties located in a producing field in south Texas (“the south Texas acquisition”). The properties were acquired in a cash transaction with a private investor group for $33.5 million. The acquisition, which was effective December 31, 2002, was financed with the Company’s existing credit facility. Nine producing wells were acquired at the time of the

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acquisition. Ten successful development wells and one development dry hole have been drilled in the field since the acquisition date. Additional wells are expected to be drilled over the next few years to fully develop the field.

Coal Royalty and Land Management

In PVR’s December 2002 Peabody Acquisition, the Partnership acquired two properties containing approximately 120 million tons of coal reserves from Peabody for 1,522,325 million common units, 1,240,833 million Class B common units (a combined common unit value of $57.0 million) and $72.5 million in cash. The acquisition included approximately $6.1 million, or 293,700 Class B units, held in escrow pending certain title transfers at December 31, 2002. As a result of the units held in escrow, approximately five million tons of coal reserves and 293,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2002. In July 2003, 241,000 Class B common units were released from escrow in exchange for certain title transfers in New Mexico. In July 2003, all of the Class B common units were converted to common units, in accordance with their terms, upon the approval of our common unitholders. As of December 31, 2003, 52,700 common units remained in escrow pending Peabody acquiring and transferring to us certain of the West Virginia reserves we purchased. As a result of the units held in escrow, approximately one million tons of coal reserves and 52,700 common units were not included in property, plant and equipment or partners’ capital, respectively, at December 31, 2003. Approximately two-thirds of the reserves purchased from Peabody are located on the Lee Ranch property in New Mexico, which Peabody continues to operate as a surface mining operation. The balance of the reserves is in northern West Virginia, which Peabody also continues to operate. All of these reserves are being leased back to Peabody for royalty rates which escalate annually over the life of the property’s production. As part of the transaction, Peabody will receive the right to share in the general partner’s incentive distribution rights, if any, in exchange for additional properties Peabody may source to the Partnership in the future. The cash portion of the transaction was funded with long-term debt and $26.4 million in proceeds from the sale of U.S. Treasury notes. The acquired coal reserves had existing productive operations that have been included in the Partnership’s statements of income since the closing date.

In PVR’s August 2002 Upshur Acquisition, the Partnership acquired the coal mineral interests to approximately 16 million tons of coal reserves located on the Upshur properties in northern Appalachia for $12.3 million in cash. The Upshur Acquisition was the Partnership’s first exposure outside of central Appalachia. The properties, which include approximately 18,000 mineral acres, contain predominantly high sulfur, high BTU coal reserves.

In May 2001, the Partnership acquired the Fork Creek property in West Virginia, which is now referred to as the West Coal River property, by purchasing approximately 53 million tons of coal reserves for $33 million in cash. In early 2002, the operator at West Coal River filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. West Coal River’s operations were subsequently idled on March 4, 2002. The operator continued to pay minimum royalties to the Partnership until it recovered its lease on August 31, 2002. In November 2002, the Partnership purchased various infrastructure at West Coal River, including a 900-ton per hour coal preparation plant and a unit train loadout facility and a railroad-granted rebate on coal loaded through the facility for $5.1 million, and it assumed approximately $2.4 million in reclamation liabilities and approximately $0.6 million of stream mitigation obligations. The Partnership leased this property in May 2003 and has assigned all reclamation and mitigation liabilities to the new lessee, which agreed to be responsible for those liabilities. The new lessee began operations in the third quarter of 2003.

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Results of Operations

Selected Financial Data—Consolidated

Included in net income for 2003 was $1.4 million, or $0.15 per diluted share, related to the adoption of Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.” This amount is included in the oil and gas segment’s contribution to net income.

The 2001 results included a pre-tax gain on the sale of securities of approximately $54.7 million ($35.5 million after tax). This amount is included in “Corporate and Other”. 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. This amount was included in the oil and gas segment’s contribution to net income.

Consolidated Net Income

Net income for the Company totaled $28.5 million in 2003, an increase of 136 percent over 2002. The increase was driven by higher oil and gas production volumes and increased market prices for crude oil and natural gas.

Oil and Gas Segment

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

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Selected Financial and Operating Data—Oil and Gas

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Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

Revenues. Oil and gas total revenues increased $53.3 million to $124.8 million in 2003 from $71.5 million in 2002.

Crude oil and natural gas production increased to 23.8 Bcfe in 2003, a 14 percent increase over 20.8 Bcfe in 2002. The increase was primarily due to the south Texas acquisition in January 2003 and the drilling programs in 2003 and 2002. Increased oil and natural gas production accounted for approximately $11.2 million, or 21 percent, of the $53.3 million increase in total oil and gas revenues from 2002 to 2003.

Approximately 84 percent of our 2003 production was natural gas, for which the average natural gas price received during 2003 was $5.31 per Mcf compared with $3.35 per Mcf in 2002, a 59 percent increase. The average oil price received was $26.91 per barrel for 2003, up 14 percent from $23.63 per barrel in 2002. Increased oil and natural gas prices accounted for approximately $41.4 million, or 78 percent, of the $53.3 million increase in total oil and gas revenues from 2002 to 2003.

Due to the volatility of crude oil and natural gas prices, we will hedge the price received for sales volumes through the use of swaps and costless collars in accordance with our Corporate policy. Gains and losses from hedging activities are included in revenues when the hedged production occurs. We recognized a loss on settled hedging activities of $6.1 million in 2003 and a loss of $1.1 million in 2002.

Operating expenses. Lease operating expenses increased from $9.3 million in 2002 to $12.1 million in 2003. The increase related to operations associated with the south Texas acquisition in January 2003 and new producing wells resulting from successful drilling activities over the last twelve months. In addition to new operations, there were increased well workover costs associated with various fields.

Exploration expenses for the years ended December 31, 2003 and 2002 consisted of the following (in thousands):

Exploration expenses increased from $7.5 million in 2002 to $15.5 million in 2003. The increase was primarily due to unsuccessful exploratory wells and the additional purchase of seismic data to evaluate both existing and new prospects during 2003 compared to 2002. There were three unsuccessful exploratory attempts in both years; however, the location, type and depth of the wells drilled changed between years. The unsuccessful wells in 2003 were primarily in the Gulf Coast region, while the unsuccessful wells in 2002 were in the Appalachia region, which has smaller, less costly drilling projects than the Gulf Coast region.

Taxes other than income taxes increased from $5.6 million in 2002 to $9.5 million in 2003. The increased taxes were a result of the increased revenues due to the higher prices received for natural gas and crude oil as well as increased production in 2003 as compared to 2002.

Oil and gas depreciation, depletion and amortization (“DD&A”) expense increased from $26.3 million in 2002 to $33.2 million in 2003. This increase was primarily due to higher production, as discussed earlier, and an increase in the weighted average DD&A rate from $1.27 per Mcfe in 2002 to $1.39 per Mcfe in 2003. The increase in the weighted average DD&A rate was the result of a greater percentage of production coming from fields which carry higher reserve replacement cost averages.

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

Revenues. Oil and gas total revenues increased $13.7 million to $71.5 million in 2002 from $57.8 million in 2001 primarily due to an increase in crude oil and natural gas production, offset by a decrease in average realized prices.

Crude oil and natural gas production increased to 20.8 Bcfe in 2002, a 47 percent increase over 14.1 Bcfe in 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 $1.1 million in 2002 and a gain of $1.9 million in 2001.

Operating expenses. Lease operating expenses 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 for the years ended December 31, 2002 and 2001 consisted of the following (in thousands):

Exploration expenses decreased from $11.5 million in 2001 to $7.5 million in 2002 primarily due to amounts expensed for three unsuccessful exploratory wells in 2002 compared to five in 2001, and the reduced write-offs of unproved property in 2002 compared to 2001. Offsetting these decreases were additional seismic expenditures of $4.9 million in 2002, up from $2.4 million in 2001.

Taxes other than income taxes increased from $4.4 million in 2001 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.

DD&A expense increased to $26.3 million in 2002 from $16.4 million in 2001. This increase was primarily due to higher production, as discussed earlier, and an increase in the weighted average DD&A rate from $1.16 per Mcfe in 2001 to $1.27 per Mcfe in 2002. The increased DD&A rate resulted from revisions in reserve estimates and additional capital investment.

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Coal Royalty and Land Management Segment (PVR)

The coal royalty and land management segment includes PVR’s 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. Approximately 72 percent of the Partnership’s 2003 coal royalty revenues and 99 percent of its 2002 coal royalty revenues were based on the higher of a percentage of the gross sales price or a fixed price per ton of coal sold, with pre-established minimum monthly or annual payments. The balance of the Partnership’s 2003 and 2002 coal royalty revenues were based on fixed royalty rates which escalate annually, also with pre-established monthly minimums. In addition to coal royalty revenues, the Partnership generates coal service revenues from fees charged to lessees for the use of coal preparation and transportation facilities. The Partnership also generates revenues from the sale of timber on its properties.

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