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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, 2004

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  ¨

The aggregate market value of common stock held by non-affiliates of the registrant was $659,289,014 as of June 30, 2004 (the last business day of its most recently completed second fiscal quarter), based on the last sale price of such stock as quoted on the New York Stock Exchange. For purposes of making this calculation only, the registrant has defined affiliates as including all directors and executive officers, but excluding any institutional shareholders owning more than ten percent of the Registrant’s Common Stock.

As of March 1, 2005, 18,497,131 shares of common stock of the registrant were issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE:

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PENN VIRGINIA CORPORATION AND SUBSIDIARIES

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PART I

Item 1—Business

General

Penn Virginia Corporation (“Penn Virginia” or the “Company”) is a Virginia corporation founded in 1882 whose common units are traded on the New York Stock Exchange under the symbol PVA. 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, 2004, we had proved reserves of approximately 6.3 million barrels of oil and condensate and 316 billion cubic feet (“Bcf”) of natural gas, or 354 billion cubic feet equivalent (“Bcfe”).

We are also indirectly involved in the businesses engaged in by Penn Virginia Resource Partners, L.P. (the “Partnership” or “PVR”), a Delaware limited partnership whose common units are traded on the New York Stock Exchange under the symbol PVR. The Partnership owns and manages coal properties. The Partnership does not operate any mines, but rather leases its coal reserves to various mining operators in exchange for royalty payments. 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 transloading facilities to some of its lessees and to other third party industrial end-users. The Partnership also generates revenues from the sale of standing timber on its properties. On March 3, 2005, the Partnership acquired a midstream gas gathering and processing business with locations in the mid-continent area of Oklahoma and the Texas panhandle from Cantera Natural Gas, LLC. See further discussion of this acquisition in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Acquisitions – Coal Royalty and Land Management – Midstream Oil and Gas.”

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, 2004, we owned approximately 44.5 percent of the Partnership, consisting of a two percent general partner interest and a 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 and Segments

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 and coal services businesses. 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 21, “Segment Information,” in the Notes to Consolidated Financial Statements for financial information concerning our business segments. In March 2005, we entered a third business segment when PVR acquired a natural gas gathering and processing business. See further discussion of this acquisition in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Acquisitions – Coal Royalty and Land Management – Midstream Oil and Gas.”

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, 2004, we had 354 Bcfe of proved reserves, of which 89 percent was natural gas. Seventy-four percent of those proved reserves were proved developed reserves. During 2004, 396 thousand barrels of oil and condensate and 22.1 Bcf of natural gas, net to our interest, were produced from continuing operations compared with 625 thousand barrels and 20.1 Bcf in 2003. We received average prices of $33.75 and $26.91 per barrel for crude oil and $6.27 and $5.31 per thousand cubic feet (“Mcf”) for natural gas in 2004 and 2003, respectively. We

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also drilled 152 gross (98.5 net) wells in 2004, of which 135 gross (90.0 net) wells were development and 17 gross (8.5 net) wells were exploratory. A total of one development well (0.3 net) and seven gross (4.4 net) exploratory wells were not successful and three gross (2.6 net) exploratory wells were under evaluation at December 31, 2004.

Transportation

The majority of our natural gas production is transported to market on five major pipeline or transmission systems. NiSource Inc., Crosstex Energy Services LTD, Dominion Transmission, Inc., Duke Energy Corporation and Gulf South Pipeline Company, LP, transported 22 percent, 20 percent, 11 percent, 11 percent and 10 percent, respectively, of our 2004 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, “Business – Risks Associated with Business Activities – Oil and Gas – Transportation.”

In 2004, we entered into contracts which provide firm transportation capacity rights for specified volumes per day on a pipeline system for terms ranging from one to 10 years. The contracts require us to pay transportation demand charges regardless of the amount of pipeline capacity we use. We may sell excess capacity to third parties at our discretion. We have an agreement to sell to a third party a portion of our capacity available under the firm transportation commitments. We also sell excess capacity to third parties on a month-by-month basis.

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, 2004, two customers of the oil and gas segment, Dominion Transmission, Inc. and Crosstex Energy Services LTD, accounted for approximately 14 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 and crude oil 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 losses on settled hedging activities of $5.9 million, $6.1 million, and $1.1 million in 2004, 2003, and 2002, respectively. In 2004, we hedged approximately 36 percent of our natural gas production at an average NYMEX Henry Hub floor price of $3.93 per MMbtu and a ceiling price of $5.99 per MMbtu for costless collars, and an average $4.70 per MMbtu for swaps. For crude oil, we hedged approximately 45 percent of our 2004 crude oil production using fixed price swaps with an average price of $29.78 per barrel. See Note 10, “Hedging Activities,” in the Notes to Consolidated Financial Statements for information about our price risk management positions for future periods.

Coal Royalty and Land Management Operations

General

At December 31, 2004, the Partnership’s properties contained approximately 558 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 coal mines. The Partnership earns coal royalty revenues, based on long-term lease agreements, from 29 coal mining operators actively mining under 55 separate leases at 65 mines. Approximately 79 percent of PVR’s coal royalty revenues earned in 2004 and 72 percent of those earned in 2003 were derived under leases providing that PVR receives the higher of a percentage of gross sales price or a fixed price per ton of coal sold (“market-sensitive leases”), with pre-established minimum monthly or annual payments. The balance of royalty revenues earned by PVR during 2004 and 2003 was derived under leases containing fixed royalty rates per ton of coal mined and sold (“fixed rate leases”). The royalty rates under those leases escalate annually with pre-established monthly minimums (see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Acquisitions – Coal Royalty and Land Management” regarding the Peabody Acquisition).

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Coal Royalties

The Partnership’s lessees mined approximately 31.2 million tons of coal in 2004 from PVR’s properties and paid an average royalty of $2.23 per ton, compared with approximately 26.5 million tons mined in 2003 at an average royalty of $1.90 per ton. In 2004, PVR’s lessees mined approximately 20.9 million tons of coal on properties with market-sensitive leases, with an average royalty of $2.64 per ton, compared with 15.9 million tons of coal and an average royalty of $2.28 per ton in 2003. Coal mined from fixed rate leases during 2004 totaled 10.3 million tons at an average royalty rate of $1.41 per ton, compared with 10.6 million tons and an average royalty rate of $1.33 per ton in 2003.

The Partnership also 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 2.6 MMbf in 2004, compared with 5.3 MMbf in 2003.

Coal Services

The Partnership generates coal services revenues from fees charged to lessees for use of the Partnership’s coal preparation and transloading facilities. The majority of these fees have been generated by the Partnership’s unit train loadout facility located on its Wise property. 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 also earns revenues through its joint venture with Massey Energy Company, which owns and operates coal handling facilities used by third party industrial end-users. The Partnership recognized $3.4 million in coal services revenues in 2004, compared to $2.1 million in 2003. Such amounts are reported as other revenues in the Consolidated Statements of Income.

Partnership Distributions

Cash Distributions. The Partnership paid cash distributions of $2.12 per common and subordinated unit during the year ended December 31, 2004. In the first quarter of 2005, the Partnership made a quarterly distribution of $0.5625 ($2.25 annualized). For the remainder of 2005, the Partnership expects to make quarterly distributions of $0.62 ($2.48 annualized) 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 $17.3 million and $16.8 million in 2004 and 2003, respectively.

Subordination Period. During the subordination period, which we describe below, PVR’s common units have the right to receive distributions of available cash from operating surplus in an amount equal to the minimum quarterly distribution, plus arrearages in the payment of any minimum quarterly distribution from prior quarters, before any distributions of available cash from operating surplus can be made on the subordinated units. The minimum quarterly distribution is $0.50 per unit ($2.00 annualized).

Definition of Subordination Period. The subordination period began on October 30, 2001, and will continue until the first day of any quarter beginning after September 30, 2006, in which each of the following events occur:

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Early Conversion of Subordinated Units. Before the end of the subordination period, 50 percent of the subordinated units, or up to 3,824,940 subordinated units were or will be eligible for conversion into common units on a one-for-one basis immediately after the distribution of available cash to partners in respect of any quarter ending on or after:

The early conversions occur if at the end of the applicable quarter each of the following three tests are met:

Because PVR met these financial tests at September 30, 2004, 25 percent of the subordinated units converted to common units on November 12, 2004.

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 incentive distributions rights are payable as follows:

If for any quarter:

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

In each case, the amount of the target distribution set forth above is exclusive of any distributions to common unitholders to eliminate any cumulative arrearages in payment of the minimum quarterly distribution on the

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common units. In conjunction with the acquisition of certain reserves from Peabody Energy Corporation (“Peabody”) in 2002, 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. PVR has not purchased any additional assets from Peabody.

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 that have greater financial and operational resources. Many such companies not only engage in the acquisition, exploration, development and production of oil and natural gas reserves, but also carry on refining operations, electricity generation and the marketing of refined products. We also compete with major and independent oil and gas companies in the marketing and sale of oil and natural gas, and the oil and natural gas industry in general competes with other industries supplying energy and fuel to industrial, commercial and individual consumers. We compete with other oil and natural gas companies in attempting to secure drilling rigs and other equipment necessary for drilling and completion of wells. Such equipment may be in short supply from time to time.

Price Volatility

Historically, natural gas and crude oil prices have been volatile. These prices rise and fall based on changes in market demand and changes in the political, regulatory and economic climate and other factors that affect commodities markets that are generally outside of our control. Some of our projections and estimates are based on assumptions as to the future prices of natural gas and crude oil. These price assumptions are used for planning purposes. We expect our assumptions will change over time and that actual prices in the future may differ from our estimates. Any substantial or extended decline in the actual prices of natural gas 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. Production could be adversely affected by disruptions or curtailments of the operations of pipelines for maintenance or replacement as transportation options are limited.

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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.

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

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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.

Risks Associated with Business Activities – Coal Royalty and Land Management

Partnership Distributions

Although the Partnership expects to make quarterly cash distributions of $0.62 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, and some of the competitors of the Partnership’s lessees have significantly larger financial and operating resources than most of the Partnership’s lessees. The Partnership’s lessees primarily compete with both large and small producers in Appalachia as well as in the western United States. The lessees 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, demand for metallurgical coal, access to transportation, 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 which permit the high sulfur coal 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,

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including the costs of reclamation and mine closure. However, the Partnership does require some smaller lessees to deposit into escrow certain funds for reclamation and mine closure costs or post performance bonds for these costs. Although the lessees typically accrue adequate amounts for these costs, their future operating results would be adversely affected if they later determined these accruals to be insufficient. Compliance with these laws has substantially increased the cost of coal mining for all domestic coal producers.

In addition, the 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 coal mined by the Partnership’s lessees. 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. Nitrogen oxides are naturally occurring byproducts of coal combustion that lead to the formation of ozone. In a February 2001 decision, the U.S. Supreme Court largely upheld the EPA’s position, although it remanded the EPA’s ozone implementation policy for further consideration. Details regarding the new particulate standard itself are still subject to judicial challenge. These ozone restrictions will require electric power generators to further reduce nitrogen oxide emissions. 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. However, on January 30, 2004, the 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, in 29 states. Like other environmental regulations, these standards and future standards could result in a decreased demand for coal.

In addition to EPA proposals, various members of Congress have proposed so-called multi-pollutant bills, which could regulate nitrogen oxides, sulfur dioxide and other emissions, including carbon dioxide, from power plants that combust coal, and the regulation of greenhouse gases that might contribute to global warming could occur either pursuant to regulatory changes under the Clean Air Act, regulations by states or future U.S. treaty obligations. Moreover, a number of states have proposed to regulate emissions of mercury and are proposing in some cases to set limits on emissions of carbon dioxide and in other cases to implement a cap and trade program to reduce emissions of carbon dioxide. The uncertainty about the regulation of mercury and carbon dioxide in particular is substantial, as a number of lawsuits have been filed challenging both proposals by EPA for a cap-and trade program for mercury and EPA’s conclusion that carbon dioxide is not covered by the Clean Air Act. While the details of proposed initiatives to regulate air emissions vary, and the outcome of legislative, regulatory and judicial disputes cannot be predicted, there is certainly a movement toward increased regulation of emissions of pollutants from the combustion of fossil fuels, including coal. If such initiatives are enacted into law, power plants could choose to shift away from coal as a fuel source to meet these requirements.

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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, with obligations including reclamation and restoration of 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.

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.

A ruling on July 8, 2004, which was made by the District Court in connection with a third lawsuit, may impair the Partnership’s lessees’ ability to obtain permits that are needed to conduct surface mining operations. In this case, Ohio Valley Environmental Coalition v. Bulen, the District Court determined that the Army Corps of Engineers (the “Corps”) violated the Clean Water Act (“CWA”) and other federal statutes when it issued Nationwide Permit 21 (“NWP21”). This ruling is currently on appeal, but no decision has been issued by the appeals court as of yet.

In January of 2005, Kentucky Riverkeepers, Inc. and several other groups filed suit in federal district court in Kentucky challenging the legality of NWP21, and seeking to enjoin the Corps from issuing any general permits thereunder for fills associated with coal mining in Kentucky. Should the district court hearing this case follow the reasoning of Ohio Valley Environmental Coalition v. Bulen and similarly enjoin the Corps from issuing general permits for coal mining under that general permit, companies seeking permits under Section 404 of the CWA in Kentucky may have to file for individual permits that may result in increases in coal mining costs. The Partnership does not have a substantial amount of reserves in Kentucky and does not expect that its lessees would be affected significantly by the outcome in this case.

West Virginia Anti-degradation Policy. A September 2003 decision by the District Court in Ohio Valley Environmental Coalition v. Whitman vacated the EPA’s approval of the State of West Virginia’s anti-degradation implementation policy, which applies to discharges into waters that have been designated as high quality waters by the State. 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 District Court ruled that this exemption and certain other provisions of the West Virginia anti-degradation policy were not consistent with the requirements of the CWA. The EPA Region III subsequently sent a letter to the West Virginia Department of Environmental Protection approving portions of its plan, denying approval of other portions pending further study, and recommending the removal of other provisions of the plan. The West Virginia Department of Environmental Protection is reportedly reviewing this letter. The Partnership’s lessees seek permits to discharge into high quality waters under a new policy which does not include such an exception. As a result of this decision, 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.

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Mine Health and Safety Laws. The operations of the Partnership’s lessees are subject to stringent health and safety standards that have been imposed by federal legislation since the adoption of the Mine Health and Safety Act of 1969. However, since the Partnership does not operate any mines and does not employ any coal miners, the Partnership is not subject to such laws and regulations. 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 health and safety 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 or pneumoconiosis and to some beneficiaries of miners who have 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 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 24 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, there are no 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.

See also Item 7A, “Quantitative and Qualitative Disclosures about Market Risk,” for a discussion of interest rate risk.

Employees

We had 120 employees at December 31, 2004, including 32 employees who directly provide services for PVR through its general partner. We consider our relations with our employees to be favorable.

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.

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Executive Officers of the Company

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

A. James Dearlove—Mr. Dearlove has served in various capacities with the Company since 1977, including as President and Chief Executive Officer and a Director of the Company since May 1996, President and Chief Operating Officer of the Company from 1994 to May 1996, Senior Vice President of the Company from 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 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 2001, Mr. Pici served as Vice President – 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 Region 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 serves as a director of the Virginia Mining Association, Powell River Project and Eastern 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 2000 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 LLP, where she practiced securities, banking and general corporate law.

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

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Company, including Vice President of Commercial Operations—Texas Pipelines and Processing, Vice President of Business Development and Director of Business Development. 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.

Common Abbreviations and Definitions

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, gas and coal 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 558 million tons of proven and probable coal reserves to which the Partnership had rights as of December 31, 2004, PVR owned the mineral interests and the majority of related surface rights to 519 million tons, or 93 percent, and leased the remaining 39 million tons, or seven 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, 2004, 2003 and 2002.

Proved Reserves

The following table presents certain information regarding our proved reserves as of December 31, 2004, 2003 and 2002. 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 25, “Supplemental Information on Oil and Gas Producing Activities (Unaudited),” in the Notes to Consolidated Financial Statements. Our estimates of proved reserves in the table above are consistent with those filed by us with other federal agencies.

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The standardized measure of discounted future net cash flows, which represents the present value of future net revenues after income taxes discounted at 10 percent, was $590 million, $512 million, and $355 million as of December 31, 2004, 2003 and 2002, respectively. For information on the changes in standardized measure of discounted future net cash flows, see Note 25, “Supplemental Information on Oil and Gas Producing Activities (Unaudited),” in the Notes to Consolidated Financial Statements.

In accordance with the SEC’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, 2004, and estimated future costs as of December 31, 2004. 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 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.

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Acreage

The following table sets forth our developed and undeveloped acreage at December 31, 2004. The acreage is located in the eastern and Gulf Coast onshore 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 three exploratory wells under evaluation at the end of 2004 include a horizontal Devonian shale well in West Virginia, a coalbed methane (“CBM”) well in Mississippi and a horizontal CBM well in Virginia. The Company expects to determine the commercial viability of these wells in the first half of 2005.

The 10 exploratory wells under evaluation at the end of 2003 are CBM wells drilled and completed in the Cherokee Basin in Chase and Greenwood Counties, Kansas. In 2004, the Company determined that these wells were not commercially viable, resulting in a $4.4 million write-off.

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Productive Wells

The number of productive oil and gas wells in which we had a working interest at December 31, 2004, 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 1,799 gross wells.

Information Regarding Coal Royalty and Land Management Properties

At December 31, 2004, the Partnership’s coal reserves were located on 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, 2004, the Partnership had approximately 558 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, workings or drill holes; grade and/or quality are computed from the results of detailed sampling, and (b) the sites for inspection, sampling and measurement are spaced so closely, and the geologic character is so well-defined, that the size, shape, 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 more widely spaced 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 exploration 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, 2004:

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 are compiled using geological data taken from thousands of drill holes, geophysical logs, 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, 2004, the Partnership owned an estimated 167 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 2004.

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PART II

Item 5—Market for the Registrant’s Common Equity 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.

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Item 6—Selected Financial Data

Five Year Selected Financial Data

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:

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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 $17.3 million of cash distributions from PVR during 2004. As part of our ownership of PVR’s general partner, we also own the rights, referred to as incentive distribution rights, to receive an increasing percentage of quarterly distributions of available cash from operating surplus after certain levels of cash distributions have been achieved. As of December 31, 2004, PVR had achieved a level of distribution to allow us to receive an increased percentage of available cash. See Item 1, “Business – Coal Royalty and Land Management Operations,” for more information on incentive distribution rights.

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 continue to execute a program combining relatively low risk, moderate return development drilling in Appalachia, Mississippi and east Texas and north Louisiana with higher risk, higher return exploration and development drilling in the onshore Gulf Coast, supplemented periodically with acquisitions. In addition to our conventional development program, we have continued to expand our presence in unconventional plays by developing CBM gas reserves in Appalachia. By employing horizontal drilling techniques, we expect to continue to increase the value from the CBM-prospective properties we own. We are committed to expanding our oil and gas reserves and production primarily by using our ability to generate exploratory prospects and development drilling programs internally.

We budgeted approximately $146 million for oil and gas capital expenditures in 2005. We do not budget major acquisitions of oil and gas properties. Borrowings against our credit facility were $76 million out of $150 million available as of December 31, 2004, and we expect to fund our 2005 budgeted capital expenditures with internal cash flow, supplemented by credit facility borrowings as needed.

In the coal royalty and land management segment, PVR continually evaluates acquisition opportunities that are accretive to cash available for distribution to PVR unitholders, 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 natural gas assets.

During the first quarter of 2005, PVR made capital expenditures of approximately $191 million, plus usual closing adjustments, for the acquisition of a midstream natural gas business from Cantera Natural Gas LLC (“Cantera”). PVR funded this acquisition at closing with debt from a new, expanded credit facility, which PVR expects to reduce with proceeds from an anticipated secondary public offering of common units during the first quarter of 2005. PVR also anticipates 2005 capital expenditures of $0.3 million for coal services related projects and other property and equipment, which it believes can be funded with cash flow provided by operating activities.

2004 Performance—Oil and Gas Segment

Our oil and gas strategy has been to increase our presence in CBM and other unconventional natural gas to build a significant inventory of predictable, low risk development prospects, and to selectively drill exploration opportunities which could make a meaningful difference to the Company’s production and reserve profile. During 2004, we believe progress was made in each area.

In 2004, we increased our oil and gas production to 24.5 Bcfe, a three percent increase over 23.8 Bcfe produced in 2003. This increase was the result of production from successful exploratory drilling projects in south Louisiana

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and the east Texas and north Louisiana Cotton Valley project, increased drilling in our Mississippi Selma Chalk fields and our Appalachia horizontal CBM project. This increase was offset primarily by production declines in several south Texas fields and a curtailment on two natural gas pipelines serving the Company’s assets in southern West Virginia, which particularly affected the deliverability of the horizontal CBM program. The curtailments lasted from May through October and restricted 2004 production by approximately 1.1 Bcf. Average daily oil and gas production increased to 70.7 MMcfe in the fourth quarter of 2004 compared to 67.1 MMcfe in the fourth quarter of 2003.

We took steps to prevent future curtailments in order to accommodate the expected increases in gas volumes from our horizontal CBM program. We constructed a 15 mile, 12-inch pipeline and acquired long-term firm transportation on Columbia Gas Transmission’s pipeline system effective in the fourth quarter of 2004.

Commodity prices, in particular for natural gas, were the largest single factor affecting our financial results in 2004. Price volatility in the natural gas market has been high in the last few years. Throughout 2002, 2003 and 2004, the NYMEX futures market traded at record price levels for natural gas. Our realized natural gas price in 2004 was $6.27 per Mcf, net of $0.17 per Mcf hedging loss. As part of our risk management strategy, we use financial instruments to hedge natural gas and, to a lesser extent, oil prices.

Our total oil and gas reserves at the end of 2004 were 354 Bcfe, an increase of 10 percent over 2003. Approximately 89 percent of our reserves at year-end 2004 were natural gas. Net of revisions, we added approximately 57 Bcfe of proved reserves primarily from extensions, discoveries and additions, replacing 233 percent of our 2004 production of 24.5 Bcfe. We drilled a total of 152 gross (98.5 net) wells during 2004, including 135 gross (90.0 net) development wells and 17 gross (8.5 net) exploratory wells. One development well (0.3 net) and seven gross (4.4 net) exploratory wells were not successful and 3 gross (2.6 net) exploratory wells were under evaluation at December 31, 2004.

During 2004, we continued to expand our CBM production and reserve base in central Appalachia through leasehold acquisitions and the use of a proprietary horizontal drilling technology. The technology is owned by our partner, and we have the right to use the technology under our agreement with our partner in a 16,000 square mile area of mutual interest (“AMI”) covering virtually all of central Appalachia. We acquired over 75,000 acres during 2004 and now control over 360,000 acres of CBM-prospective leasehold within the AMI. By accelerating production from these normally long-lived reserves, this drilling technique has resulted in increased projected rates of return on the horizontal CBM wells drilled through 2004. This technique was used to drill and complete 20 gross (11.0 net) horizontal CBM wells during 2004, and our horizontal CBM production increased to 2.1 Bcfe in 2004 from 1.1 Bcfe in 2003. In 2005, our capital budget includes $21 million to drill 29 gross (15 net) horizontal CBM wells in Appalachia and $11 million for lease acquisitions and pipeline infrastructure. During 2004, a horizontal well was drilled in the Devonian shale and is currently under evaluation.

In 2003, we drilled 10 wells as part of a conventional CBM pilot project in the Cherokee Basin of southeastern Kansas, where we control over 40,000 acres. After performing production testing for a over a year, we evaluated the project to be non-commercial, resulting in a charge to exploration expense in the fourth quarter of 2004 of approximately $4.4 million.

Early in 2004, we entered into a joint venture with GMX Resources, Inc. [NASDAQ:GMXR] to drill development wells in the North Carthage Field in east Texas. The wells are drilled and completed in the Cotton Valley formation with the Travis Peak and Petit formations also present in some wells. Through the joint venture, we have drilling rights on approximately 13,500 acres. We estimate that 80 to 100 wells could ultimately be drilled on this acreage. Outside the joint venture area, we have acquired an additional 18,000 acres also prospective in the Cotton Valley formation.

In our Cotton Valley play in east Texas and north Louisiana, which includes the GMX joint venture, 23 gross (15.6 net) wells were drilled during 2004 with 100 percent success. Net Cotton Valley production for the year was 1.1 Bcfe, up from the 0.1 Bcfe produced in 2003 from operations preceding our GMX joint venture. We have continued to expand our leasehold position in the Cotton Valley play in east Texas, and we plan to begin drilling on the new acreage in the second half of 2005. The 2005 budget includes approximately $27 million to drill 24 gross (17 net) wells in east Texas and north Louisiana.

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Another of our important development areas is the Selma Chalk formation in Mississippi. During 2004, 44 gross (43.6 net) Selma Chalk wells were drilled and all of the wells were successful. Production from this play was 4.9 Bcfe in 2004, up 29 percent from 3.8 Bcfe in 2003. Our 2005 budget includes approximately $23 million to drill 65 gross (64 net) wells in 2005.

During 2004, we used our Gulf Coast seismic data base, which now exceeds 8,000 square miles, to continue to increase our inventory of internally generated exploration prospects in both south Louisiana and south Texas. During 2004, we drilled 11 gross (3.0 net) exploratory wells in the Gulf Coast region. Of the 11 wells, six were successful, with three located in south Louisiana and three in south Texas. In St. Mary Parish of south Louisiana, we participated in the successful drilling of our first prospect identified with a 100 square mile proprietary 3D seismic program that was shot in 2003. The well, in which we have a 25 percent working interest, was drilled to a total depth of approximately 18,000 feet and found productive sands in two different intervals. Fourteen additional prospects have been identified within this 3D seismic survey, two of which are expected to be drilled in 2005. After drilling a successful exploratory well and a development well in the Creole area in Cameron Parish in 2003, an additional exploratory well was drilled in 2004 which was a dry hole, and another exploratory well was drilling at year end 2004. The Creole area, in which we have a 30 percent working interest, is expected to continue to be an active area for us in 2005, with three exploratory wells planned. Since commencing its south Louisiana exploratory drilling efforts in 2003, we have drilled eight successful exploratory wells in 10 attempts.

In south Texas, a successful Vicksburg exploratory well in which we have a 25 percent working interest was drilled in the Kingsville Field in Kleberg County. In the Esperanza project area in Nueces County, where we have a 33 percent working interest, two dry Vicksburg wells and one dry Frio well were drilled. The Vicksburg prospects were higher risk, high potential projects. We participated with a 20 percent working interest in a successful Frio exploratory well in Hidalgo County.

Our Board of Directors has approved a 2005 oil and gas capital expenditures budget of $146 million. We do not budget major acquisitions of oil and gas properties. Based on 2005 NYMEX prices of $6.00 per MMbtu for natural gas and $35.00 per barrel of oil, we expect to fund this capital budget using internally generated cash flows from oil and gas production, supplemented by borrowings under our credit facility as needed. Our credit facility consists of a $150 million commitment which, as of January 31, 2005, had outstanding borrowings of $76 million. Additionally, to provide greater certainty of having sufficient operating cash flows to fund our oil and gas capital expenditures program, we have an active commodity price hedging program. As of January 31, 2005, we had natural gas hedges in place for 2005 covering approximately 25,800 MMbtu per day. These positions, primarily in the form of costless collars, provide average floor and ceiling prices of $5.25 and $7.40 per MMbtu, respectively, and cover approximately one third of our expected 2005 natural gas production. We also have approximately 13,700 MMbtu per day of natural gas hedged for the first half of 2006 at average floor and ceiling prices of $5.20 and $9.60 respectively. Oil production comprises an insignificant part of our expected production, and no oil production was hedged as of January 31, 2005.

2004 Performance—Coal Royalty and Land Management Segment (PVR)

PVR’s coal royalty revenues increased 38 percent from $50.3 million in 2003 to $69.6 million in 2004. This increase was a result of an increase in coal production of 4.7 million tons, or 18 percent, combined with a 17 percent increase in average gross royalties per ton from $1.90 in 2003 to $2.23 in 2004. This production increase was primarily related to a longwall mining operation started by one of PVR’s lessees in the first quarter of 2004 on PVR’s Coal River property. This longwall operation increased production by 2.6 million tons and added $5.6 million in revenues in 2004. The addition of a mine operator and a new mine by another Coal River lessee contributed approximately 0.7 million tons of coal production, or $3.1 million of revenue. Increased demand also fueled a coal sales price increase in the region, which in turn resulted in a seven percent increase in average gross royalty per ton on the Coal River property, from $2.42 per ton in 2003 to $2.60 per ton in 2004. Revenues at the Wise property increased by $5.9 million primarily as a result of a 19 percent increase in the average royalty rate from $2.29 per ton in 2003 to $2.72 per ton in 2004. Revenues from the Spruce Laurel property increased by $1.9 million, primarily as the result of a 23 percent increase in the average gross royalty per ton on the Spruce Laurel property, from $2.07 per ton in 2003 to $2.54 per ton in 2004.

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As part of PVR’s coal land management business, PVR owns approximately 167 million board feet of standing timber. PVR generally sells cutting rights to various contractors who cut in advance of a mining project. Timber revenues in 2004 were $0.7 million, down from $1.0 million in 2003.

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.

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 resulted in additional coal services revenues, supplementing revenues from the Shober loading facility, opened in 2002, in Virginia. PVR also spent approximately $4.4 million to construct a third large-scale coal loading facility on its Coal River property, and the facility began operating in February 2004. Coal services revenues increased to $3.4 million in 2004 from $2.1 million in 2003, and are expected to increase to over $4.1 million in 2005. PVR believes that these types of fee-based infrastructure assets provide good investment and cash flow opportunities for the Partnership, and it continues to look for additional investments of this type as well as other primarily fee-based assets, including oil and gas midstream assets.

The Partnership was able to take advantage of another growth opportunity in 2004 by acquiring from affiliates of Massey Energy Company for $28.4 million a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. This joint venture is pursuing additional projects to build and operate coal handing facilities for industrial customers.

In March 2005, PVR purchased a natural gas gathering and processing business from Cantera for $191 million cash. These midstream assets include approximately 3,400 miles of gas gathering pipelines that supply three natural gas processing facilities which have 160 million cubic feet per day (MMcfd) of total capacity. The assets derive revenue primarily from the sharing of proceeds on the sale of natural gas and natural gas liquids under contracts with natural gas producers and from fees charged for gathering and processing of natural gas and other related services. The assets are located in four geographic regions: the Oklahoma and Texas Panhandles, north central Oklahoma, north central Texas and the Arkoma basin.

Critical Accounting Policies and Estimates

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

Reserves

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

Proved reserves are the estimated quantities of crude oil, condensate and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with 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.

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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 differing from 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 $0.7 million, $0.4 million and $0.8 million for 2004, 2003 and 2002, 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 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. Pursuant to Statement of Financial Accounting Standards (“SFAS”) No. 19, “Financial Accounting and Reporting by Oil and Gas Reporting Companies,” costs of drilling exploratory wells are initially capitalized and later charged to expense if upon determination the wells do not justify commercial development. Occasionally, an exploratory well may be determined to have found oil and gas reserves, but classification of those reserves as proved cannot be made when drilling is completed. If classification of proved reserves cannot be made in an area requiring a major capital expenditure, the cost of drilling the exploratory well is carried as an asset provided that (a) there have been sufficient reserves found to justify completion as a producing well if the required capital expenditure is made and (b) further well completion work needs to be performed or additional exploratory wells need to be drilled and those activities are either underway or firmly planned for the near future. If either of these two criteria is not met, exploratory well costs are expensed. For all other exploratory wells, costs of exploratory wells are expensed if the reserves cannot be classified as proved after one year following the completion of drilling.

A portion of the carrying value of the Company’s oil and gas properties is attributable to unproved properties. At December 31, 2004, the costs attributable to unproved properties were approximately $61 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.

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

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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.

Hedging Activities

We enter into derivative financial instruments that qualify for hedge accounting under SFAS No. 133. Hedge accounting affects the timing of revenue recognition in our statements of income, as a majority of the gain or loss from a contract qualifying as a cash flow hedge is deferred as to statement of income recognition. The position reflected in the statement of income is based on the actual settlements with the counterparty. We include this gain or loss in oil and gas revenues. If our natural gas and crude oil derivatives did not qualify for hedge accounting or we chose not to use this hedge accounting methodology, we could experience significant changes in the estimate of non-cash derivative gain or loss recognized in revenue due to swings in the value of these contracts. These fluctuations could be especially significant in a volatile pricing environment.

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 does not operate any mines, it does not have access to actual production and revenue information until approximately 30 days following the month of production. Therefore, the financial results of the Partnership 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.

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 acquisition. Ten successful development wells and one development dry hole have been drilled in the field since the acquisition date.

Coal Royalty and Land Management

Midstream Oil and Gas. In March 2005, PVR purchased from Cantera a natural gas gathering and processing business with assets in Oklahoma and Texas for $191 million of cash (the “Cantera Acquisition”). As a result of this acquisition, PVR now owns and operates a business, under the name PVR Midstream LLC, consisting of a set of midstream assets that include approximately 3,400 miles of gas gathering pipelines that supply three natural gas processing facilities with 160 MMcfd of total capacity. PVR will derive revenues from this business primarily from the sharing of sales proceeds of natural gas and natural gas liquids under contracts with natural gas producers and from fees charged for the gathering and processing of natural gas and other related services. These midstream assets are located in four geographic regions: the Oklahoma and Texas Panhandles, north central Oklahoma, north central Texas and the Arkoma basin. Concurrent with the closing of the Cantera Acquisition, the Partnership completed an expanded five-year credit facility led by PNC Capital Markets and RBC Capital Markets, consisting of a $150 million revolving credit facility and a $110 million term loan. PVR used the term loan and a portion of the revolving credit facility to fund the Cantera Acquisition. The new revolving credit facility was also used to pay off PVR’s existing Revolver which had an outstanding balance of $30.0 million at December 31, 2004. The Partnership anticipates using a combination of its credit facility and new equity capital to permanently finance this acquisition. As of December 31, 2004, the Partnership capitalized $0.7 million for costs related to the Cantera Acquisition.

In order to protect the projected cash flows of the acquisition from the risk of commodity price volatility, in January 2005, PVR entered into notional derivative contracts for approximately 75 percent of the net volume of

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natural gas liquids expected to be sold from April 2005 through December 2006. The underlying commodity prices that PVR expects to realize in future periods, after giving effect to the derivative contracts, are expected to exceed the commodity prices used in financial evaluation of the acquisition.

Since the time PVR entered into the derivative contracts, futures prices of natural gas liquids have increased significantly. As of March 2, 2005, the aggregate fair value of these derivative contracts was unfavorable to PVR. Upon closing of the Cantera Acquisition and documenting hedge effectiveness, these derivative contracts are expected to qualify as cash flow hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (“SFAS No. 133”). (See our previous discussion of hedging activities in “Critical Accounting Policies and Estimates.”) From the time the derivative contracts were executed until completion of the hedge effectiveness documentation, the derivative contracts do not qualify for hedge accounting. The unfavorable change in the derivative contracts’ fair value was estimated to be approximately $8.9 million as of March 2, 2005. The fair value at the date the derivative contracts qualify for hedge accounting will be recognized as a non-cash reduction of earnings for PVR in the first quarter of 2005. The $8.9 million as of March 2, 2005, is the most recently available fair value estimate and is subject to change until the derivative contracts qualify for hedge accounting. All cash settlements of these derivative contracts will be paid or received over the 21-month term of the contracts.

Coal Handling Joint Venture. In July 2004, the Partnership acquired from affiliates of Massey Energy Company a 50 percent interest in a joint venture formed to own and operate end-user coal handling facilities. The purchase price was $28.4 million and was funded through the Partnership’s credit facility. The joint venture owns coal handling facilities which unload shipments and store and transfer coal for three industrial coal consumers in the chemical, paper and lime production industries located in Tennessee, Virginia and Kentucky, respectively. A combination of fixed monthly fees and per ton throughput fees is paid by those consumers under long-term leases expiring between 2007 and 2019. PVR recognized equity earnings of $0.4 million related to its ownership in the joint venture in 2004. The Partnership received a joint venture distribution of approximately $1.0 million during the fourth quarter of 2004 relating to third quarter operations.

Coal Loadout Facility. In January 2004, the Partnership completed the construction of a new coal loadout facility for one of its lessees on its Coal River property in West Virginia. The $4.4 million loadout facility is designed for the high-speed loading of 150-car unit trains and became operational on February 1, 2004. This facility generated additional revenues of approximately $0.5 million in 2004, and the Partnership believes it resulted in increased coal production of approximately 0.4 million tons from this lessee during 2004.

Coal Reserves. In December 2002, the Partnership acquired (the “Peabody Acquisition”) 120 million tons of proven and probable coal reserves (the “Reserves”) located in New Mexico (80 million tons) and West Virginia (40 million tons) from Peabody Energy Corporation (“Peabody”). All of the Reserves were leased back to subsidiaries of Peabody by the Partnership. The Peabody Acquisition provided geographic diversity by exposing PVR to new markets in the western United States and in northern Appalachia. The inclusion of Peabody as a significant part of PVR’s lessee mix added strength and stability to its lessee group. The acquisition was funded with $72.5 million of cash, 1.53 million of the Partnership’s common units and 1.23 million of the Partnership’s Class B common units. All of the Class B common units were converted into common units in accordance with their terms, upon the approval of PVR common unitholders in July 2003. In December 2003 and January 2004, Peabody sold 1.15 million of its common units in public offerings sponsored by the Partnership, and, as of December 31, 2004, Peabody held 0.84 million of PVR’s common units.

In August 2002, the Partnership purchased approximately 16 million tons of proven and probable coal reserves located on the Upshur properties in northern Appalachia for $12.3 million (the “Upshur Acquisition”). The properties, which include approximately 18,000 mineral acres, contain predominantly high sulfur, high BTU coal reserves.

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Results of Operations

Selected Financial Data—Consolidated

Included in net income for 2003 was $1.4 million, or $0.08 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.

Consolidated Net Income

Net income for the Company totaled $33.4 million in 2004, an increase of 17 percent over 2003. The higher earnings were primarily the result of both increased natural gas and coal production and higher prices for natural gas, crude oil and coal.

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

Year Ended December 31, 2004, Compared to Year Ended December 31, 2003

Production. The increase in production was primarily due to production from successful exploratory drilling projects in south Louisiana, the Cotton Valley play in east Texas and north Louisiana, increased drilling in our Selma Chalk fields in Mississippi and our horizontal CBM drilling project in Appalachia, offset primarily by production declines in several south Texas fields and a pipeline curtailment in Appalachia.

Revenues. Increased realized prices for natural gas and crude oil accounted for approximately $24.0 million, or 89 percent, of the increase in total oil and gas revenues from 2003 to 2004. Approximately 90 percent of our 2004 production was natural gas, for which the average realized price received was $6.27 per Mcf compared with $5.31 per Mcf in 2003, an 18 percent increase. The average realized oil price received was $33.75 per barrel for 2004, up 25 percent from $26.91 per barrel in 2003.

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Due to the volatility of crude oil and natural gas prices, we hedge the price received for certain sales volumes through the use of swaps and costless collars in accordance with our hedging policy. Gains and losses from hedging activities are included in revenues when the hedged production occurs. In 2004, approximately 36 percent of our natural gas was hedged, primarily using costless collars, at an average floor price of $3.93 per MMbtu and ceiling price of $5.99 per MMbtu. We also hedged approximately 45 percent of our crude oil production using fixed price swaps with an average price of $29.78 per barrel. We recognized a loss on settled hedging activities of $5.9 million in 2004, compared with a loss of $6.1 million in 2003.

Operating expenses. The oil and gas segment’s aggregate operating costs and expenses in 2004 increased primarily due to higher exploration expenses, higher depreciation, depletion and amortization (“DD&A”) and a loss on assets held for sale.

Exploration expenses for the years ended December 31, 2004 and 2003, consisted of the following (in thousands):